Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☑ No ☐

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ☑ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

~~Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes~~ ☐ No ☑.

~~As of October 31, 2017, there were 5,000,000 9.0% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units outstanding.~~

Targa Resources Partners LP’s (together with its subsidiaries, “we,” “us,” “our,” “TRP” or “the Partnership”) reports, filings and other public announcements may from time to time contain statements that do not directly or exclusively relate to historical facts. Such statements are “forward-looking statements.” You can typically identify forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, by the use of forward-looking statements, such as “may,” “could,” “project,” “believe,” “anticipate,” “expect,” “estimate,” “potential,” “plan,” “forecast” and other similar words.

All statements that are not statements of historical facts, including statements regarding our future financial position, business strategy, budgets, projected costs and plans and objectives of management for future operations, are forward-looking statements.

These forward-looking statements reflect our intentions, plans, expectations, assumptions and beliefs about future events and are subject to risks, uncertainties and other factors, many of which are outside our control. Important factors that could cause actual results to differ materially from the expectations expressed or implied in the forward-looking statements include known and unknown risks. Known risks and uncertainties include, but are not limited to, the following risks and uncertainties:

Although we believe that the assumptions underlying our forward-looking statements are reasonable, any of the assumptions could be inaccurate, and, therefore, we cannot assure you that the forward-looking statements included in ~~this Quarterly Report on Form 10-Q for the quarter ended September 30, 2017 (“Quarterly Report”)~~ will prove to be accurate. Some of these and other risks and uncertainties that could cause actual results to differ materially from such forward-looking statements are more fully described in our Annual Report. Except as may be required by applicable law, we undertake no obligation to publicly update or advise of any change in any forward-looking statement, whether as a result of new information, future events or otherwise.

~~As generally used in the energy industry and in this Quarterly Report, the identified terms have the following meanings:~~

~~CONSOLIDATED BALANCE SHEETS~~(Exact name of registrant as specified in its charter)

September 30, 2017

December 31, 2016

(Unaudited)

(In millions)

ASSETS

Current assets:

Cash and cash equivalents

$
103.9

$
68.0

Trade receivables, net of allowances of $0.1 and $0.9 million at September 30, 2017 and December 31, 2016

709.2

673.2

Inventories

267.4

137.7

Assets from risk management activities

18.7

16.8

Other current assets

80.5

31.5

Total current assets

1,179.7

927.2

Property, plant and equipment

13,685.2

12,511.9

Accumulated depreciation

(3,616.4
)

(2,821.0
)
Property, plant and equipment, net

10,068.8

9,690.9

Intangible assets, net

2,214.8

1,654.0

Goodwill, net

256.6

210.0

Long-term assets from risk management activities

13.7

5.1

Investments in unconsolidated affiliates

222.1

240.8

Other long-term assets

16.5

16.9

Total assets

$
13,972.2

$
12,744.9

LIABILITIES AND OWNERS' EQUITY

Current liabilities:

Accounts payable and accrued liabilities

$
949.2

$
773.9

Accounts payable to Targa Resources Corp.

71.7

61.0

Liabilities from risk management activities

80.9

49.1

Current debt obligations

528.4

275.0

Total current liabilities

1,630.2

1,159.0

Long-term debt

3,933.6

4,177.0

Long-term liabilities from risk management activities

14.9

26.1

Deferred income taxes, net

26.9

26.9

Other long-term liabilities

484.9

205.3

Contingencies (see Note 16)

Owners' equity:

Series A preferred limited partners
Issued

Outstanding

120.6

120.6

September 30, 2017

5,000,000

5,000,000

December 31, 2016

5,000,000

5,000,000

Common limited partners
Issued

Outstanding

6,592.1

5,939.9

September 30, 2017

275,168,410

275,168,410

December 31, 2016

275,168,410

275,168,410

General partner
Issued

Outstanding

810.1

796.7

September 30, 2017

5,629,136

5,629,136

December 31, 2016

5,629,136

5,629,136

Accumulated other comprehensive income (loss)

(70.1
)

(61.8
)

7,452.7

6,795.4

Noncontrolling interests in subsidiaries

429.0

355.2

Total owners' equity

7,881.7

7,150.6

Total liabilities and owners' equity

$
13,972.2

$
12,744.9
��

See notes to consolidated financial statements.

Delaware		65-1295427
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

811 Louisiana St, Suite 2100, Houston, Texas		77002
(Address of principal executive offices)		(Zip Code)

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes☑ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes☐ No☑

As of November 2, 2020, there were 5,000,000 9.0% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units outstanding.

Targa Resources Partners LP’s (together with its subsidiaries, “we,” “us,” “our,” “TRP” or the “Partnership”) reports, filings and other public announcements may from time to time contain statements that do not directly or exclusively relate to historical facts. Such statements are “forward-looking statements.” You can typically identify forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, by the use of forward-looking statements, such as “may,” “could,” “project,” “believe,” “anticipate,” “expect,” “estimate,” “potential,” “plan,” “forecast” and other similar words.

Additionally, while we have not been previously materially impacted by prior outbreaks of illnesses, pandemics or other public health crises, there are potential risks to us from the continued impact on global demand for commodities related to the COVID-19 pandemic. The COVID-19 pandemic reduced economic activity and the related demand for energy commodities, which contributed to weakened commodity prices compared to historical levels and price volatility during the nine months ended September 30, 2020 and is expected to continue to impact demand over the short-to-medium term.

Although we believe that the assumptions underlying our forward-looking statements are reasonable, any of the assumptions could be inaccurate, and, therefore, we cannot assure you that the forward-looking statements included in this Quarterly Report on Form 10-Q for the quarter ended September 30, 2020 (“Quarterly Report”) will prove to be accurate. Some of these and other risks and uncertainties that could cause actual results to differ materially from such forward-looking statements are more fully described in our Annual Report. Except as may be required by applicable law, we undertake no obligation to publicly update or advise of any change in any forward-looking statement, whether as a result of new information, future events or otherwise.

As generally used in the energy industry and in this Quarterly Report, the identified terms have the following meanings:

					September 30, 2020			December 31, 2019
					(Unaudited)
					(In millions)
ASSETS
Current assets:
Cash and cash equivalents					$	248.0		$	291.1
Trade receivables, net of allowances of $0.1 and $0.0 million at September 30, 2020 and December 31, 2019						609.8			855.2
Inventories						261.7			161.5
Assets from risk management activities						88.9			103.3
Deposits						110.1			35.4
Held for sale assets						62.2			137.7
Other current assets						18.7			18.8
Total current assets						1,399.4			1,603.0
Property, plant and equipment, net						12,292.9			14,549.0
Intangible assets, net						1,417.6			1,735.0
Long-term assets from risk management activities						79.5			35.5
Investments in unconsolidated affiliates						718.8			738.7
Other long-term assets						86.4			83.3
Total assets					$	15,994.6		$	18,744.5

LIABILITIES AND OWNERS' EQUITY
Current liabilities:
Accounts payable						617.2		$	952.9
Accrued liabilities						40.3			50.7
Dividends payable						96.5			92.7
Interest payable						95.3			125.4
Accrued taxes						85.1			62.0
Accounts payable to Targa Resources Corp.						195.9			193.8
Liabilities from risk management activities						121.1			104.1
Current debt obligations						261.9			382.2
Held for sale liabilities						3.6			6.4
Total current liabilities						1,516.9			1,970.2
Long-term debt						7,217.2			7,005.2
Long-term liabilities from risk management activities						62.9			40.8
Deferred income taxes, net						23.0			23.0
Other long-term liabilities						261.3			260.0
Contingencies (see Note 11)
Owners' equity:
Series A preferred limited partners	Issued		Outstanding			120.6			120.6
September 30, 2020		5,000,000		5,000,000
December 31, 2019		5,000,000		5,000,000
Common limited partners	Issued		Outstanding			2,921.3			5,022.7
September 30, 2020		275,168,410		275,168,410
December 31, 2019		275,168,410		275,168,410
General partner	Issued		Outstanding			735.0			778.0
September 30, 2020		5,629,136		5,629,136
December 31, 2019		5,629,136		5,629,136
Accumulated other comprehensive income (loss)						(119.5	)		122.5
						3,657.4			6,043.8
Noncontrolling interests						3,255.9			3,401.5
Total owners' equity						6,913.3			9,445.3
Total liabilities and owners' equity					$	15,994.6		$	18,744.5

See notes to consolidated financial statements.

	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016			2020			2019			2020			2019
	(Unaudited)												(Unaudited)
	(In millions)												(In millions)
Revenues:
Sales of commodities	$	1,871.5		$	1,398.7		$	5,353.1		$	3,882.9		$	1,840.8		$	1,594.2		$	4,900.8		$	5,254.8
Fees from midstream services		260.3			253.6			759.0			795.5			274.3			308.3			786.7			942.4
Total revenues		2,131.8			1,652.3			6,112.1			4,678.4			2,115.1			1,902.5			5,687.5			6,197.2
Costs and expenses:
Product purchases		1,663.1			1,222.7			4,737.8			3,378.9			1,303.2			1,328.1			3,346.8			4,415.7
Operating expenses		155.5			143.0			462.6			413.9			181.9			200.2			565.1			600.7
Depreciation and amortization expense		208.3			184.0			602.8			563.6			203.7			244.3			647.3			718.9
General and administrative expense		46.6			44.0			139.4			132.3			56.3			65.6			171.7			212.3
Impairment of property, plant and equipment		378.0			—			378.0			—
Impairment of goodwill		—			—			—			24.0
Impairment of long-lived assets														0			0			2,442.8			0
Other operating (income) expense		0.6			4.9			17.2			6.1			72.2			18.4			73.8			21.7
Income (loss) from operations		(320.3	)		53.7			(225.7	)		159.6			297.8			45.9			(1,560.0	)		227.9
Other income (expense):
Interest expense, net		(51.9	)		(57.9	)		(169.5	)		(171.2	)		(94.9	)		(84.2	)		(283.0	)		(229.2	)
Equity earnings (loss)		0.2			(2.2	)		(16.6	)		(11.4	)		18.6			10.0			54.1			15.9
Gain (loss) from financing activities		—			—			(10.7	)		21.4			(13.7	)		0			47.4			(1.4	)
Gain (loss) from sale of equity-method investment														0			65.8			0			65.8
Change in contingent considerations		126.8			0.3			125.6			0.3			0			0			0			(8.8	)
Other, net		0.2			1.0			(2.7	)		0.8			1.3			0			2.0			0
Income (loss) before income taxes		(245.0	)		(5.1	)		(299.6	)		(0.5	)		209.1			37.5			(1,739.5	)		70.2
Income tax (expense) benefit		—			(1.0	)		4.2			—			0			0			0			0
Net income (loss)		(245.0	)		(6.1	)		(295.4	)		(0.5	)		209.1			37.5			(1,739.5	)		70.2
Less: Net income attributable to noncontrolling interests		9.7			4.7			25.9			13.5
Less: Net income (loss) attributable to noncontrolling interests														100.1			76.6			108.1			144.3
Net income (loss) attributable to Targa Resources Partners LP	$	(254.7	)	$	(10.8	)	$	(321.3	)	$	(14.0	)	$	109.0		$	(39.1	)	$	(1,847.6	)	$	(74.1	)

Net income attributable to preferred limited partners	$	2.8		$	2.8		$	8.4		$	8.4		$	2.8		$	2.8		$	8.4		$	8.4
Net income (loss) attributable to general partner		(5.2	)		29.0			(6.6	)		68.2			2.1			(0.9	)		(37.2	)		(1.7	)
Net income (loss) attributable to common limited partners		(252.3	)		(42.6	)		(323.1	)		(90.6	)		104.1			(41.0	)		(1,818.8	)		(80.8	)
Net income (loss) attributable to Targa Resources Partners LP	$	(254.7	)	$	(10.8	)	$	(321.3	)	$	(14.0	)	$	109.0		$	(39.1	)	$	(1,847.6	)	$	(74.1	)

		Three Months Ended September 30,						Nine Months Ended September 30,							Three Months Ended September 30,						Nine Months Ended September 30,
		2017			2016			2017			2016				2020			2019			2020			2019
		(Unaudited)						(Unaudited)							(Unaudited)
		(In millions)						(In millions)							(In millions)
Net income (loss)	Net income (loss)	$	(245.0	)	$	(6.1	)	$	(295.4	)	$	(0.5	)	Net income (loss)	$	209.1		$	37.5		$	(1,739.5	)	$	70.2
Other comprehensive income (loss):	Other comprehensive income (loss):													Other comprehensive income (loss):
Commodity hedging contracts:	Commodity hedging contracts:													Commodity hedging contracts:
Change in fair value	Change in fair value		(106.8	)		12.9			(10.5	)		(40.5	)	Change in fair value		(128.7	)		118.2			(102.6	)		167.8
Settlements reclassified to net income			2.1			(8.1	)		2.2			(50.6	)
Settlements reclassified to revenues														Settlements reclassified to revenues		(19.2	)		(41.5	)		(139.4	)		(106.1	)
Other comprehensive income (loss)	Other comprehensive income (loss)		(104.7	)		4.8			(8.3	)		(91.1	)	Other comprehensive income (loss)		(147.9	)		76.7			(242.0	)		61.7
Comprehensive income (loss)	Comprehensive income (loss)		(349.7	)		(1.3	)		(303.7	)		(91.6	)	Comprehensive income (loss)		61.2			114.2			(1,981.5	)		131.9
Less: Comprehensive income attributable to noncontrolling interests			9.7			4.7			25.9			13.5
Less: Comprehensive income (loss) attributable to noncontrolling interests														Less: Comprehensive income (loss) attributable to noncontrolling interests		100.1			76.6			108.1			144.3
Comprehensive income (loss) attributable to Targa Resources Partners LP	Comprehensive income (loss) attributable to Targa Resources Partners LP	$	(359.4	)	$	(6.0	)	$	(329.6	)	$	(105.1	)	Comprehensive income (loss) attributable to Targa Resources Partners LP	$	(38.9	)	$	37.6		$	(2,089.6	)	$	(12.4	)

Accumulated

Limited

Limited

General

Other

Treasury

Non-

Partner

Partner

Partner

Comprehensive

Units

controlling

Preferred

Amount

Common

Amount

Units

Amount

Income (Loss)

Units

Amount

Interests

Total

(Unaudited)

(In millions, except units in thousands)

Balance, December 31, 2016

5,000

$
120.6

275,168

$
5,939.9

5,629

$
796.7

$
(61.8
)

—

$
—

$
355.2

$
7,150.6

Contributions from Targa
   Resources Corp.

—

—

—

1,587.5

—

32.5

—

—

—

—

1,620.0

Purchase of noncontrolling
   interests in subsidiary

—

—

—

—

—

—

—

—

—

(12.5
)

(12.5
)
Distributions to noncontrolling
   interests

—

—

—

—

—

—

—

—

—

(33.4
)

(33.4
)
Contributions from noncontrolling
   interests

—

—

—

—

—

—

—

—

—

93.8

93.8

Other comprehensive income
  (loss)

—

—

—

—

—

—

(8.3
)

—

—

—

(8.3
)
Net income (loss)

—

8.4

—

(323.1
)

—

(6.6
)

—

—

—

25.9

(295.4
)
Distributions

—

(8.4
)

—

(612.2
)

—

(12.5
)

—

—

—

—

(633.1
)
Balance, September 30, 2017

5,000

$
120.6

275,168

$
6,592.1

5,629

$
810.1

$
(70.1
)

—

$
—

$
429.0

$
7,881.7

																Accumulated
	Limited					Limited					General					Other			Non-
	Partner					Partner					Partner					Comprehensive			controlling
	Preferred		Amount			Common		Amount			Units		Amount			Income (Loss)			Interests			Total
	(Unaudited)
	(In millions, except units in thousands)

Balance, June 30, 2020		5,000	$	120.6			275,168	$	2,865.2			5,629	$	733.8		$	28.4		$	3,230.9		$	6,978.9
Contributions from Targa Resources Corp.		0		0			0		0			0		0			0			0			0
Distributions to noncontrolling interests		—		0			—		0			—		0			0			(110.3	)		(110.3	)
Contributions from noncontrolling interests		—		0			—		0			—		0			0			7.7			7.7
Non-cash allocation to noncontrolling interests		0		0			0		0			0		0			0			27.5			27.5
Other comprehensive income (loss)		—		0			—		0			—		0			(147.9	)		0			(147.9	)
Net income (loss)		—		2.8			—		104.1			—		2.1			0			100.1			209.1
Distributions		—		(2.8	)		—		(48.0	)		—		(0.9	)		0			0			(51.7	)
Balance, September 30, 2020		5,000	$	120.6			275,168	$	2,921.3			5,629	$	735.0		$	(119.5	)	$	3,255.9		$	6,913.3

																Accumulated
	Limited					Limited					General					Other		Non-
	Partner					Partner					Partner					Comprehensive		controlling
	Preferred		Amount			Common		Amount			Units		Amount			Income (Loss)		Interests			Total
	(Unaudited)
	(In millions, except units in thousands)

Balance, June 30, 2019		5,000	$	120.6			275,168	$	5,703.1			5,629	$	791.9		$	109.9	$	3,276.2		$	10,001.7
Contributions from Targa Resources Corp.		0		0			0		9.8			0		0.2			0		0			10.0
Sale of ownership interests in subsidiaries		—		0			—		0			—		0			0		0			0
Distributions to noncontrolling interests		—		0			—		0			—		0			0		(87.2	)		(87.2	)
Contributions from noncontrolling interests		—		0			—		0			—		0			0		115.3			115.3
Other comprehensive income (loss)		—		0			—		0			—		0			76.7		0			76.7
Net income (loss)		—		2.8			—		(41.0	)		—		(0.9	)		0		76.6			37.5
Distributions		—		(2.8	)		—		(234.8	)		—		(4.8	)		0		0			(242.4	)
Balance, September 30, 2019		5,000	$	120.6			275,168	$	5,437.1			5,629	$	786.4		$	186.6	$	3,380.9		$	9,911.6

																Accumulated
	Limited					Limited					General					Other			Non-
	Partner					Partner					Partner					Comprehensive			controlling
	Preferred		Amount			Common		Amount			Units		Amount			Income (Loss)			Interests			Total
	(Unaudited)
	(In millions, except units in thousands)

Balance, December 31, 2019		5,000	$	120.6			275,168	$	5,022.7			5,629	$	778.0		$	122.5		$	3,401.5		$	9,445.3
Contributions from Targa Resources Corp.		0		0			0		49.0			0		1.0			0			0			50.0
Distributions to noncontrolling interests		—		0			—		0			—		0			0			(314.5	)		(314.5	)
Contributions from noncontrolling interests		—		0			—		0			—		0			0			33.3			33.3
Non-cash allocation to noncontrolling interests		0		0			0		0			0		0			0			27.5			27.5
Other comprehensive income (loss)		—		0			—		0			—		0			(242.0	)		0			(242.0	)
Net income (loss)		—	8.4				—		(1,818.8	)		—		(37.2	)		0			108.1			(1,739.5	)
Distributions		—		(8.4	)		—		(331.6	)		—		(6.8	)		0			0			(346.8	)
Balance, September 30, 2020		5,000	$	120.6			275,168	$	2,921.3			5,629	$	735.0		$	(119.5	)	$	3,255.9		$	6,913.3

Accumulated

Limited

Limited

General

Other

Treasury

Non-

Partner

Partner

Partner

Comprehensive

Units

controlling

Preferred

Amount

Common

Amount

Units

Amount

Income (Loss)

Units

Amount

Interests

Total

(Unaudited)

(In millions, except units in thousands)

Balance, December 31, 2015

5,000

$
120.6

184,871

$
4,550.4

3,773

$
1,735.3

$
86.8

212

$
(10.3
)

$
420.1

$
6,902.9

Compensation on equity grants

—

—

—

2.2

—

—

—

—

—

—

2.2

Distribution equivalent rights

—

—

—

(0.2
)

—

—

—

—

—

—

(0.2
)
Issuance of common units under
   compensation program

—

—

30

—

—

—

—

—

—

—

—

Units tendered for tax
   withholding obligations

—

—

(1
)

—

—

—

—

1

(0.1
)

—

(0.1
)
Cancellation of treasury units

—

—

—

(10.2
)

—

(0.2
)

—

(213
)

10.4

—

—

Contributions from Targa
   Resources Corp.

—

—

58,621

1,167.2

1,197

23.8

—

—

—

—

1,191.0

Distributions to
   noncontrolling interests

—

—

—

—

—

—

—

—

—

(16.8
)

(16.8
)
Contributions from
   noncontrolling interests

—

—

—

—

—

—

—

—

—

32.7

32.7

Other comprehensive
   income (loss)

—

—

—

—

—

—

(91.1
)

—

—

—

(91.1
)
Net income (loss)

—

8.4

—

(90.6
)

—

68.2

—

—

—

13.5

(0.5
)
Distributions

—

(8.4
)

—

(440.2
)

—

(94.0
)

—

—

—

—

(542.6
)
Balance, September 30, 2016

5,000

$
120.6

243,521

$
5,178.6

4,970

$
1,733.1

$
(4.3
)

—

$
—

$
449.5

$
7,477.5

																Accumulated
	Limited					Limited					General					Other		Non-
	Partner					Partner					Partner					Comprehensive		controlling
	Preferred		Amount			Common		Amount			Units		Amount			Income (Loss)		Interests			Total
	(Unaudited)
	(In millions, except units in thousands)

Balance, December 31, 2018		5,000	$	120.6			275,168	$	6,227.2			5,629	$	802.6		$	124.9	$	1,270.8		$	8,546.1
Contributions from Targa Resources Corp.		0		0			0		196.0			0		4.0			0		0			200.0
Sale of ownership interests in subsidiaries		—		0			—		(10.5	)		—		(0.2	)		0		1,619.7			1,609.0
Distributions to noncontrolling interests		—		0			—		0			—		0			0		(172.6	)		(172.6	)
Contributions from noncontrolling interests		—		0			—		0			—		0			0		518.7			518.7
Other comprehensive income (loss)		—		0			—		0			—		0			61.7		0			61.7
Net income (loss)		—		8.4			—		(80.8	)		—		(1.7	)		0		144.3			70.2
Distributions		—		(8.4	)		—		(894.8	)		—		(18.3	)		0		0			(921.5	)
Balance, September 30, 2019		5,000	$	120.6			275,168	$	5,437.1			5,629	$	786.4		$	186.6	$	3,380.9		$	9,911.6

			Nine Months Ended September 30,
			2017			2016					Nine Months Ended September 30,
											2020			2019
		(Unaudited)								(Unaudited)
		(In millions)								(In millions)
Cash flows from operating activities	Cash flows from operating activities								Cash flows from operating activities
Net income (loss)	Net income (loss)		$	(295.4	)	$	(0.5	)	Net income (loss)		$	(1,739.5	)	$	70.2
Adjustments to reconcile net income (loss) to net cash provided by operating activities:	Adjustments to reconcile net income (loss) to net cash provided by operating activities:								Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Amortization in interest expense	Amortization in interest expense			7.1			9.8		Amortization in interest expense			7.6			6.8
Compensation on equity grants				—			2.2
Depreciation and amortization expense	Depreciation and amortization expense			602.8			563.6		Depreciation and amortization expense			647.3			718.9
Impairment of property, plant and equipment				378.0			—
Impairment of goodwill				—			24.0
Impairment of long-lived assets									Impairment of long-lived assets			2,442.8			0
Accretion of asset retirement obligations	Accretion of asset retirement obligations			3.0			3.5		Accretion of asset retirement obligations			2.6			3.7
Increase (decrease) in redemption value of mandatorily redeemable preferred interests				8.5			(18.8	)
Equity (earnings) loss of unconsolidated affiliates	Equity (earnings) loss of unconsolidated affiliates			16.6			11.4		Equity (earnings) loss of unconsolidated affiliates			(54.1	)		(15.9	)
Distributions of earnings received from unconsolidated affiliates	Distributions of earnings received from unconsolidated affiliates			8.4			1.8		Distributions of earnings received from unconsolidated affiliates			65.5			26.0
Risk management activities	Risk management activities			13.9			11.7		Risk management activities			(214.2	)		100.8
(Gain) loss on sale or disposition of assets				16.6			5.7
(Gain) loss on sale or disposition of business and assets									(Gain) loss on sale or disposition of business and assets			58.0			3.6
Write-downs of assets												13.5			17.9
(Gain) loss from financing activities	(Gain) loss from financing activities			10.7			(21.4	)	(Gain) loss from financing activities			(47.4	)		1.4
Change in contingent considerations included in Other expense (income)				(125.6	)		(0.3	)
(Gain) loss from sale of equity-method investment												0			(65.8	)
Change in contingent considerations									Change in contingent considerations			0			8.8
Changes in operating assets and liabilities, net of business acquisitions:	Changes in operating assets and liabilities, net of business acquisitions:								Changes in operating assets and liabilities, net of business acquisitions:
Receivables and other assets	Receivables and other assets			(91.5	)		(28.3	)	Receivables and other assets			170.0			108.0
Inventories	Inventories			(136.4	)		(27.8	)	Inventories			(115.8	)		(89.7	)
Accounts payable and other liabilities				46.5			32.1
Accounts payable, accrued liabilities and other liabilities									Accounts payable, accrued liabilities and other liabilities			(151.3	)		(9.5	)
Interest payable									Interest payable			(30.1	)		12.2
Net cash provided by operating activities	Net cash provided by operating activities			463.2			568.7		Net cash provided by operating activities			1,054.9			897.4
Cash flows from investing activities	Cash flows from investing activities								Cash flows from investing activities
Outlays for property, plant and equipment	Outlays for property, plant and equipment			(866.6	)		(425.0	)	Outlays for property, plant and equipment			(803.1	)		(2,433.8	)
Outlays for business acquisition, net of cash acquired				(570.8	)		—
Proceeds from sale of business and assets									Proceeds from sale of business and assets			135.9			2.7
Investments in unconsolidated affiliates	Investments in unconsolidated affiliates			(7.5	)		(4.6	)	Investments in unconsolidated affiliates			(2.2	)		(243.7	)
Proceeds from sale of equity-method investment															70.3
Return of capital from unconsolidated affiliates	Return of capital from unconsolidated affiliates			2.2			3.4		Return of capital from unconsolidated affiliates			10.7			1.1
Other, net	Other, net			(14.8	)		4.2		Other, net			4.7			(16.3	)
Net cash used in investing activities	Net cash used in investing activities			(1,457.5	)		(422.0	)	Net cash used in investing activities			(654.0	)		(2,619.7	)
Cash flows from financing activities	Cash flows from financing activities								Cash flows from financing activities
Debt obligations:	Debt obligations:								Debt obligations:
Proceeds from borrowings under credit facility	Proceeds from borrowings under credit facility			1,496.0			1,110.0		Proceeds from borrowings under credit facility			1,460.0			2,180.0
Repayments of credit facility	Repayments of credit facility			(1,216.0	)		(1,390.0	)	Repayments of credit facility			(1,360.0	)		(2,050.0	)
Proceeds from borrowings under accounts receivable securitization facility	Proceeds from borrowings under accounts receivable securitization facility			281.6			121.4		Proceeds from borrowings under accounts receivable securitization facility			476.4			770.0
Repayments of accounts receivable securitization facility	Repayments of accounts receivable securitization facility			(278.5	)		(115.7	)	Repayments of accounts receivable securitization facility			(596.4	)		(804.0	)
Open market purchases of senior notes				—			(534.3	)
Proceeds from issuance of senior notes									Proceeds from issuance of senior notes			1,000.0			1,500.0
Redemption of senior notes	Redemption of senior notes			(287.6	)		—		Redemption of senior notes			(831.0	)		(749.4	)
Principal payments of finance leases									Principal payments of finance leases			(9.3	)		(8.5	)
Costs incurred in connection with financing arrangements	Costs incurred in connection with financing arrangements			(0.1	)		(7.5	)	Costs incurred in connection with financing arrangements			(9.6	)		(25.1	)
Repurchase of common units under compensation plans				—			(0.1	)
Purchase of noncontrolling interests in subsidiary				(12.5	)		—
Payment of contingent consideration									Payment of contingent consideration			0			(317.1	)
Sale of ownership interests in subsidiaries									Sale of ownership interests in subsidiaries			0			1,619.7
Contributions from general partner	Contributions from general partner			32.5			23.8		Contributions from general partner			1.0			4.0
Contributions from TRC	Contributions from TRC			1,587.5			1,167.2		Contributions from TRC			49.0			196.0
Contributions from noncontrolling interests	Contributions from noncontrolling interests			93.8			32.7		Contributions from noncontrolling interests			33.3			518.7
Distributions to noncontrolling interests	Distributions to noncontrolling interests			(33.4	)		(16.8	)	Distributions to noncontrolling interests			(310.6	)		(98.9	)
Distributions to unitholders	Distributions to unitholders			(633.1	)		(542.6	)	Distributions to unitholders			(346.8	)		(921.5	)
Payments of distribution equivalent rights				—			(0.3	)
Net cash provided by (used in) financing activities	Net cash provided by (used in) financing activities			1,030.2			(152.2	)	Net cash provided by (used in) financing activities			(444.0	)		1,813.9
Net change in cash and cash equivalents	Net change in cash and cash equivalents			35.9			(5.5	)	Net change in cash and cash equivalents			(43.1	)		91.6
Cash and cash equivalents, beginning of period	Cash and cash equivalents, beginning of period			68.0			135.4		Cash and cash equivalents, beginning of period			291.1			203.3
Cash and cash equivalents, end of period	Cash and cash equivalents, end of period		$	103.9		$	129.9		Cash and cash equivalents, end of period		$	248.0		$	294.9

Except as noted within the context of each footnote disclosure, the dollar amounts presented in the tabular data within these footnote disclosures are stated in millions of dollars.

Targa Resources Partners LP is a Delaware limited partnership formed in October 2006 by our parent, Targa Resources Corp. (“Targa” or “TRC” or the “Company” or “Parent”). In this Quarterly Report, unless the context requires otherwise, references to “we,” “us,” “our,” “TRP,” or the “Partnership” are intended to mean the business and operations of Targa Resources Partners LP and its consolidated subsidiaries.

On February 17, 2016, TRC completed the previously announced transactions contemplated pursuant to the Agreement and Plan of Merger (the “TRC/TRP Merger Agreement,” and such transactions, the “TRC/TRP Merger”),

Our common units are wholly owned by ~~and among us, Targa Resources GP LLC (our “general partner” or “TRP GP”),~~ TRC and ~~Spartan Merger Sub LLC,~~no longer publicly traded as a ~~subsidiary~~result of ~~TRC (“Merger Sub”), pursuant to which TRC acquired indirectly all~~TRC’s acquisition of our outstanding common units that ~~TRC~~it and its subsidiaries did not already ~~own. Upon the terms and conditions set forth~~own in the TRC/TRP Merger Agreement, Merger Sub merged with and into TRP with TRP continuing as the surviving entity and as a subsidiary of TRC. As a result of the TRC/TRP Merger, TRC owns all of our outstanding common units.2016.

At the effective time of the TRC/TRP Merger, each outstanding TRP common unit not owned by TRC or its subsidiaries was converted into the right to receive 0.62 shares of common stock of TRC, par value $0.001 per share (“TRC shares”). No fractional TRC shares were issued in the TRC/TRP Merger, and TRP common unitholders, instead received cash in lieu of fractional TRC shares.

Pursuant to the TRC/TRP Merger Agreement, TRC has agreed to cause our common units to be delisted from the New York Stock Exchange (“NYSE”) and deregistered under the Securities Exchange Act of 1934, as amended (the “Exchange Act”). As a result of the completion of the TRC/TRP Merger, our common units are no longer publicly traded. The 5,000,000 9.00% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (the “Preferred Units”) that were issued in October 2015 remain outstanding as limited partner interests in us and continue to trade on the NYSE under the symbol ~~“NGLS PRA.~~“NGLS/PA.”

On October 19, 2016, we executed the Third Amended and Restated Agreement of Limited Partnership of Targa Resources Partners LP (the “Third A&R Partnership Agreement”), which became effective as of December 1, 2016. The Third A&R Partnership Agreement amendments include among other things (i) eliminating the incentive distribution rights (“IDRs”) held by the general partner, and related distribution and allocation provisions, (ii) eliminating the Special General Partner Interest (the “Special GP Interest” as defined in the Third A&R Partnership Agreement) held by the general partner, (iii) providing the ability to declare monthly distributions in addition to quarterly distributions, (iv) modifying certain provisions relating to distributions from available cash, (v) eliminating the Class B Unit (as defined in the Third A&R Partnership Agreement) provisions and (vi) changes to the Third A&R Partnership Agreement to reflect the passage of time and to remove provisions that are no longer applicable.

See Note 1915 – Segment Information for certain financial information regarding our business segments.

The employees supporting our operations are employed by Targa. Our consolidated financial statements include the direct costs of Targa employees deployed to our operating segments, as well as an allocation of costs associated with our usage of Targa’s centralized general and administrative services.

~~We have prepared these~~The accompanying unaudited consolidated financial statements have been prepared in accordance ~~with GAAP for interim financial information and~~ with the instructions to Form 10-Q and ~~Article 10 of Regulation S-X. Accordingly, they~~ do not include all ~~of the~~ information and ~~footnotes required by GAAP for complete financial statements. While we derived the year-end balance sheet data from audited financial statements, this interim report does not include all~~ disclosures required by ~~GAAP for annual periods. These unaudited consolidated financial statements and other~~GAAP. Therefore, this information ~~included in this Quarterly Report~~ should be read in conjunction with our consolidated financial statements and notes ~~thereto included~~contained in our Annual Report.

The ~~unaudited consolidated financial statements for the three and nine months ended September 30, 2017 include~~information furnished herein reflects all adjustments that ~~we believe~~ are, in the opinion of management, necessary for a fair statement of the results ~~for~~of the interim ~~periods.~~periods reported. All significant intercompany balances and transactions have been eliminated in consolidation. Certain amounts in prior periods ~~may~~ have been reclassified to conform to the current year presentation.

~~Our financial~~ Operating results for the three and nine months ended September 30, ~~2017~~2020 are not necessarily indicative of the results that may be expected for the ~~full year.~~year ending December 31, 2020.

The accounting policies that we follow are set forth in Note 3 – Significant Accounting Policies of the Notes to Consolidated Financial Statements in our Annual Report. ~~There~~Other than the updates noted below, there were no significant updates or revisions to our accounting policies during the nine months ended September 30, ~~2017, except as noted below.~~2020.

In ~~May 2014, the Financial Accounting Standards Board ("FASB") issued Accounting Standard Update (“ASU”) No. 2014-09,~~ ~~Revenue from Contracts with Customers (Topic 606), which supersedes the revenue recognition requirements in Topic 605,~~ ~~Revenue Recognition, and most industry-specific guidance. The update also creates a new Subtopic 340-40,~~ ~~Other Assets and Deferred Costs – Contracts with Customers~~, which provides guidance for the incremental costs of obtaining a contract with a customer and those costs incurred in fulfilling a contract with a customer that are not in the scope of another topic. The new revenue standard requires that entities should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entities expect to be entitled in exchange for those goods or services. To achieve that core principle, the standard requires a five step process of (1) identifying the contracts with customers, (2) identifying the performance obligations in the contracts, (3) determining the transaction price, (4) allocating the transaction price to the performance obligations, and (5) recognizing revenue when, or as, the performance obligations are satisfied. The amendment also requires enhanced disclosures regarding the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers.

~~With the~~ ~~issuance~~ in August ~~2015 of ASU 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date,~~ the revenue recognition standard is effective for the annual period beginning after December 15, 2017, and for annual and interim periods thereafter. Earlier adoption is permitted for annual reporting periods beginning after December 15, 2016, including interim reporting periods within that reporting period. We must retrospectively apply the new revenue recognition standard to transactions in all prior periods presented, but will have a choice between either (1) restating each prior period presented or (2) presenting a cumulative effect adjustment in the period the standard is adopted.

~~In March 2016,~~2020, the FASB issued ASU ~~2016-08,~~ ~~Revenue from~~2020-06, Debt - Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging - Contracts ~~with Customers (Topic 606)~~in Entity’s Own Equity (Subtopic 815-40): ~~Principal versus Agent Considerations~~.Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity. The amendments in this update ~~improve~~simplify the ~~operability~~accounting for convertible debt instruments and ~~understandability~~convertible preferred stock by reducing the number of accounting models and embedded conversion features that can be recognized separately from the implementation guidance on principal versus agent considerations, including clarifying that an entity should determine whether it is a principal or an agent for each specified good or service promised to a customer.primary contract. These amendments ~~are effective for fiscal years,~~also enhance transparency and ~~interim periods within those years, beginning on or after December 15, 2017, with early adoption permitted.~~

In ~~April~~ ~~2016, the FASB issued ASU 2016-10,~~ ~~Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing~~. These amendments clarify the guidance on identification of performance obligations and licensing. The amendments include that entities do not have to decide if goods and services are performance obligations if they are considered immaterial in the context of a contract. Entities are also permitted to account for the shipping and handling that takes place after the customer has gained control of the goods as actions to fulfill the contract rather than separate services. In order to identify a performance obligation in a customer contract, an entity has to determine whether the goods or services are distinct, and ASU No. 2016-10 clarifies how the determination can be made.

~~In May 2016, the FASB issued ASU 2016-12,~~ ~~Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients~~. These amendments address certain implementation issues related to assessing collectability, presentation of sales taxes, noncash consideration, and completed contracts and contract modifications at transition, and also provide additional practical expedients.

~~In December~~ ~~2016, the FASB issued ASU 2016-20,~~ ~~Technical Corrections and Improvements to Topic 606, Revenue from Contracts with Customers~~. The amendments in this update clarify the disclosure requirements for performance obligations, provide optional exemptions from the disclosure requirement for remaining performance obligations for specific situations in which an entity need not estimate variable consideration to recognize revenue and provide clarified guidance regarding impairment testing of capitalized contract costs.

We have disaggregated contracts within our two segments and are in the process of completing our review of contracts and transaction types with counterparties in order to evaluate how the new standard would impact our current revenue recognition and disclosure policies upon adoption.

Based on our progress to date, we have preliminarily concluded that the contracts within our Gathering and Processing segment where we purchase and obtain control of the entire natural gas stream are contracts with suppliers rather than customers and therefore, not included in the scope of Topic 606. However, these supplier contracts are subject to updated guidance in ASC 705, ~~Cost of Sales and Services~~, whereby any embedded fees within such contracts, which historically have been reported as “Fees from midstream services,” will be reported instead as a reduction of “Product purchases” upon adoption of Topic 606. In addition, we have concluded that in most cases, we are acting as the principal in the sale of hydrocarbons to end customers. We are continuing to assess certain Gathering and Processing contracts whereby we obtain control over some, but not all, of the natural gas and natural gas liquids stream, including arrangements where the producer takes or may elect to take a portion of the merchantable gas and/or natural gas liquids in kind. ~~Specifically, when such arrangements contain both a service revenue element and a supply element, we are in the process of determining how each element should be measured.~~

At this time, we are not anticipating a significant change in revenue recognition for the contracts within our Logistics and Marketing segment, although the potential effects of contributions in aid of construction (which may also affect certain Gathering and Processing contracts where we are acting as an agent for the producer), tiered pricing, and excess fuel are currently being evaluated. We are also anticipating additionalimprove disclosures for fixed consideration allocated to performance obligations that are unsatisfied (or partially unsatisfied) as of the end of the current reporting period, separate presentation of revenue from contracts with customersconvertible instruments and ~~non-customer revenue (i.e. the effects of derivative activity and lease revenue) as well as unbilled receivables and deferred revenue.~~

The new revenue recognition standard is effective for us on January 1, 2018, and currently we plan to adopt using the modified retrospective method and will recognize a cumulative effect adjustment, if any, in the first quarter of 2018. However, we will continue to evaluate our planned adoption method based on our views regarding stakeholder needs and a final determination on remaining accounting matters still under evaluation. We have also established a cross-functional team to assist with the implementation through documentation of process changes, identification of implementation risks, update and development of mitigating controls, determination of data requirements, and identification of changes in system mapping and configuration.

In ~~February~~ ~~2016, the FASB issued ASU 2016-02,~~ ~~Leases (Topic 842)~~. The amendments in this update require, among other things, that lessees recognize the following for all leases (with the exception of short-term leases) at the commencement date: (1) a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and (2) a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. Lessees and lessors must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. ~~We expect to adopt the amendments in the first quarter of 2019 and are currently evaluating the impacts of the amendments to our consolidated financial statements and accounting practices for leases.~~

~~In June 2016, the FASB issued ASU 2016-13,~~ ~~Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments.~~ These amendments change the measurement of credit losses for most financial assets and certain other instruments that are not measured at fair value through net income. The amendments in this update affect investments in loans, investments in debt securities, trade receivables, net investments in leases, off-balance sheet credit exposures, reinsurance receivables, and any other financial assets not excluded from the scope that have the contractual right to receive cash. The amendments replace the incurred loss impairment methodology in current GAAP with a methodology that reflects expected credit losses and requires consideration of a broader range of reasonable and supportable information to inform credit loss estimates. We expect to adopt this guidance on January 1, 2019, and are continuing to evaluate the impact on our measurement of credit losses.

~~In August 2016, the FASB issued ASU 2016-15,~~ ~~Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force)~~. These amendments clarify how entities should classify certain cash receipts and cash payments in the statement of cash flows related to the following transactions: (1) debt prepayment or extinguishment costs; (2) settlement of zero-coupon debt instruments or other debt instruments with coupon rates that are insignificant in relation to the effective interest rate of the borrowing; (3) contingent consideration payments made after a business combination; (4) proceeds from the settlement of insurance claims; (5) proceeds from the settlement of corporate-owned life insurance; (6) distributions received from equity method investees; and (7) beneficial interests in securitization transactions. Additionally, the update clarifies how the predominance principle should be applied when cash receipts and cash payments have aspects of more than one class of cash flows.earnings per share guidance. These amendments are effective for fiscal years, and interim periods within those years, beginning after December 15, ~~2017, with~~

~~early adoption permitted. We plan to adopt the applicable amendments in the first quarter of 2018 and expect a minimal effect on our consolidated financial statements.~~

In ~~October~~ ~~2016, the FASB issued ASU 2016-16,~~ ~~Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other than Inventory~~. The amendments in this update are intended to improve the accounting for the income tax consequences of intra-entity transfers of assets other than inventory. Current GAAP prohibits the recognition of current and deferred income taxes for an intra-entity asset transfer until the asset has been sold to an outside party or otherwise recovered, which is an exception to the principle of comprehensive recognition of current and deferred income taxes in GAAP. This update eliminates the exception by requiring entities to recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs. We early adopted the applicable amendments in first quarter of 2017 on a modified retrospective basis. The adoption resulted in no effect as TRP is not subject to income taxes.

In ~~January~~ ~~2017, the FASB issued ASU 2017-01,~~ ~~Business Combinations (Topic 805): Clarifying the Definition of a Business~~. The amendments clarify the definition of a business to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses by providing an initial required screen to determine when an integrated set of assets and activities is not a business. The screen requires that when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or a group of similar identifiable assets, the set is not a business. This screen reduces the number of transactions that need to be further evaluated. If the screen is not met, then the amendments (1) require that to be considered a business, a set must include, at a minimum, an input and a substantive process that together significantly contribute to the ability to create output and (2) remove the evaluation of whether a market participant could replace missing elements. The amendments also provide a framework to assist entities in evaluating whether both an input and a substantive process are present. These amendments are effective for annual periods beginning after December 15, 2017, including interim periods within those periods, with early application permitted for transactions that have not been previously reported. We will apply this guidance to all transactions completed subsequent to our adoption of these amendments.

~~In January 2017, FASB issued ASU 2017-04,~~ ~~Intangibles—Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment~~, which eliminates Step 2 from the goodwill impairment test. Step 2 required entities to compute the implied fair value of goodwill if it was determined that the carrying amount of a reporting unit exceeded its fair value. Under the amendments in this update, an entity should perform its annual, or interim, goodwill impairment test by comparing the fair value of a reporting unit with its carrying amount and should recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit’s fair value. The goodwill impairment recognized should not exceed the total amount of goodwill allocated to that reporting unit. Additionally, an entity should consider income tax effects from any tax deductible goodwill on the carrying amount of the reporting unit when measuring the goodwill impairment loss, if applicable. An entity still has the option to perform the qualitative assessment for a reporting unit to determine if the quantitative impairment test is necessary. These amendments are effective for annual or any interim goodwill impairment tests in fiscal years beginning after December 15, 2019. Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. We expect to apply these amendments for our annual goodwill impairment test as of November 30, 2017. Had we applied this new guidance for our November 2016 impairment test date, the full balance of our goodwill would have been impaired. We expect to apply these amendments for our annual goodwill impairment test as of November 30, which may result in impairment of goodwill for 2017.

~~In February 2017, FASB issued ASU 2017-05,~~ ~~Other Income—Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic 610-20)~~, which clarifies the scope of Subtopic 610-20 and adds guidance for partial sales of nonfinancial assets. Specifically, the amendments clarify that the guidance applies to all nonfinancial assets and in substance nonfinancial assets unless other specific guidance applies and defines "in substance financial asset" as an asset or group of assets for which substantially all of the fair value consists of nonfinancial assets and the group or subsidiary is not a business. These amendments also impact the accounting for partial sales of nonfinancial assets, whereby an entity that transfers its controlling interest in a nonfinancial asset, but retains a noncontrolling ownership interest, will measure the retained interest at fair value resulting in the full gain/loss recognition upon sale. ~~These amendments are effective for fiscal years, and interim periods within those years, beginning after December 15, 2017,~~2021, with early adoption permitted. This update permits the use of either the modified retrospective or full retrospective method of adoption. We are currently evaluating the ~~effect~~effects of such amendments on our consolidated financial statements.

~~Stock Compensation – Scope~~Measurement of ~~Modification Accounting~~Credit Losses

In ~~May~~ ~~2017,~~June 2016, the FASB issued ASU ~~2017-09,~~ ~~Compensation—Stock Compensation~~2016-13, Financial Instruments—Credit Losses (Topic ~~718)~~326): ~~Scope~~Measurement of ~~Modification Accounting~~, which clarifies when changes to the terms or conditions of a share-based payment award must be accounted for as modifications. Under the new guidance, an entity will apply modification accounting only if the fair value, vesting conditions or the classification of the award changes as a result of the change in terms or conditions of a share-based payment award. In addition, the new guidance clarifies that regardless of whether an entity is required to apply modification accounting, the existing disclosure requirements and other aspects of GAAP associated with modifications continue to apply. These amendments are effective for fiscal years, and interim periods within those years, beginning after December 15, 2017, with early adoption permitted. We early adopted the applicable amendments in the second quarter of 2017 and will apply the new guidance prospectively to any awards modifiedCredit Losses on ~~or after the adoption date.~~

~~In July 2017, FASB issued ASU 2017-11,~~ Earnings Per Share (Topic 260); Distinguishing Liabilities from Equity (Topic 480); Derivatives and Hedging (Topic 815): (Part I) Accounting for Certain Financial Instruments with Down Round Features, (Part II) Replacement of the Indefinite Deferral for Mandatorily Redeemable Financial Instruments of Certain Nonpublic Entities and Certain Mandatorily Redeemable Noncontrolling Interests with a Scope Exception. The amendments in this update ~~are intended to simplify~~modify the ~~accounting~~impairment model for ~~certain equity-linked~~ financial instruments, including trade and ~~embedded features with down round features that~~other receivables, held-to-maturity debt securities and other instruments.

The amendments require entities to consider historical information, current conditions, and supportable forecasts to estimate expected credit losses, which may result in earlier recognition of losses. The amendments were effective for us on January 1, 2020 and were adopted by applying the ~~strike price being reduced~~modified retrospective transition approach. The adoption did not result in a cumulative effect adjustment to retained earnings on January 1, 2020. As a result of our adoption, see Accounting Policy Updates – Allowance for Doubtful Accounts below.

Estimated losses on accounts receivable are provided through an allowance for doubtful accounts. We estimate the ~~basis~~allowance for doubtful accounts through various procedures, including extensive review of our trade receivable balances by counterparty, assessing economic events and conditions, our historical experience with counterparties, the counterparty’s financial condition and the amount and age of past due accounts.

We continuously evaluate our ability to collect amounts owed to us. Receivables are considered past due if full payment is not received by the contractual due date. These procedures also include performing account reconciliations, dispute resolution and payment confirmation. We may involve our legal counsel to pursue the recovery of defaulted trade receivables.

As the financial condition of any counterparty changes, circumstances develop or additional information becomes available, adjustments to our allowance may be required.

During the preparation of the pricing of future equity offerings. Under the new guidance, a down round feature will no longer need to be considered when determining whether certain financial instruments or embedded features should be classified as liabilities or equity instruments. That is, a down round feature will no longer preclude equity classification when assessing whether an instrument or embedded feature is indexed to an entity's own stock. In addition, the amendments clarify existing disclosure requirements for equity-classified instruments. These amendments are effective for fiscal years, and interim periods within those years, beginning after December 15, 2018, with early adoption permitted. We early adopted the applicable amendments in the secondCompany's first quarter ~~of 2017 on a retrospective basis noting no effect on our~~2019 consolidated financial ~~statements.~~

~~Targeted Improvements~~statements, the Company identified an error related to ~~Accounting~~depreciation expense on certain assets that should have been placed in-service during 2018. The Company does not believe this error is material to its previously issued historical consolidated financial statements for ~~Hedge Activities~~

~~In August 2017, FASB issued ASU 2017-12,~~ ~~Derivatives~~any of the periods impacted and ~~Hedging (Topic 815): Targeted Improvements to Accounting for Hedge Activities, which are intended to better align risk management activities and~~accordingly, has not adjusted the historical financial ~~reporting for hedging relationships.~~statements. The ~~new guidance covers multiple aspects~~Company recorded the cumulative impact of hedge accounting: (1) changes the way in which ineffectiveness is accounted, (2) allows for new hedge strategies, and (3) changes hedge disclosures. Under the new guidance, companies will have the option to perform a qualitative quarterly effectiveness assessment once the initial quantitative test has been performed. In addition, any ineffectiveness that exists is required to be recorded in other comprehensive income insteadone-time $12.5 million overstatement of in earnings as is required under current guidance. Several new hedging strategies will be allowed to be given hedge accounting treatment, most of which involve the hedging of contractually specified components. Lastly, disclosure requirements will be updated to (1) require that hedge income be presented on the same line item as the related hedged item, (2) require hedge program objectives to be disclosed, and (3) eliminate the requirement to separately disclose ineffectiveness. These amendments are effective for fiscal years, and interim periods within those years, beginning after December 15, 2018, with early adoption permitted. We plan to adopt the applicable amendments indepreciation expense during the first quarter of ~~2018 and expect an immaterial effect on our consolidated financial statements.~~2019.

On March 1, 2017, Targa completed the purchase of 100% of the membership interests of Outrigger Delaware Operating, LLC, Outrigger Southern Delaware Operating, LLC (together “New Delaware”) and Outrigger Midland Operating, LLC (“New Midland” and together with New Delaware, the “Permian Acquisition”).

We paid $484.1 million in cash at closing on March 1, 2017, and paid an additional $90.0 million in cash on May 30, 2017 (collectively, the “initial purchase price”). Subject to certain performance-linked measures and other conditions, additional cash of up to $935.0 million may be payable to the sellers of New Delaware and New Midland in potential earn-out payments that would occur in 2018 and 2019. The potential earn-out payments will be based upon a multiple of realized gross margin from contracts that existed on March 1, 2017.

New Delaware’s gas gathering and processing and crude gathering assets are located in Loving, Winkler, Pecos and Ward counties in Texas. The operations are backed by producer dedications of more than 145,000 acres under long-term, largely fee-based contracts,

with an average weighted contract life of 14 years. The New Delaware assets include 70 MMcf/d of processing capacity, and we are in the process of installing a 60 MMcf/d plant, known as the Oahu Plant, in the Delaware Basin with expectations of commencing operations in the fourth quarter of 2017. Currently, there is 40 MBbl/d of crude gathering capacity on the New Delaware system. Since March 1, 2017, financial and statistical data of New Delaware have been included in Sand Hills operations.

New Midland’s gas gathering and processing and crude gathering assets are located in Howard, Martin and Borden counties in Texas. The operations are backed by producer dedications of more than 105,000 acres under long-term, largely fee-based contracts, with an average weighted contract life of 13 years. The New Midland assets include 10 MMcf/d of processing capacity. Currently, there is 40 MBbl/d of crude gathering capacity on the New Midland system. Since March 1, 2017, financial and statistical data of New Midland have been included in SAOU operations.

New Delaware’s gas gathering and processing assets were connected to our Sand Hills system in the first quarter of 2017, and the New Midland’s gas gathering and processing assets were connected to our existing WestTX system in October 2017. We believe connecting the acquired assets to our legacy Permian footprint creates operational and capital synergies, and will afford enhanced flexibility in serving our producer customers.

On January 26, 2017, Targa completed a public offering of 9,200,000 shares of its common stock (including the shares sold pursuant to the underwriters’ overallotment option) at a price to the public of $57.65, providing net proceeds of $524.2 million. Targa used the net proceeds from this public offering to fund the cash portion of the Permian Acquisition purchase price due upon closing and for general corporate purposes.

The acquired businesses contributed revenues of $75.2 million and a net loss of $21.5 million to us for the period from March 1, 2017 to September 30, 2017, and are reported in our Gathering and Processing segment. As of September 30, 2017, we had incurred $5.6 million of acquisition-related costs. These expenses are included in Other expense in our Consolidated Statements of Operations for the nine months ended September 30, 2017.

~~Pro Forma Impact of Permian Acquisition on Consolidated Statement of Operations~~

The following summarized unaudited pro forma Consolidated Statement of Operations information for the nine months ended September 30, 2017 and September 30, 2016 assumes that the Permian Acquisition occurred as of January 1, 2016. We prepared the following summarized unaudited pro forma financial results for comparative purposes only. The summarized unaudited pro forma information may not be indicative of the results that would have occurred had we completed this acquisition as of January 1, 2016, or that would be attained in the future.

The pro forma consolidated results of operations amounts have been calculated after applying our accounting policies, and making the following adjustments to the unaudited results of the acquired businesses for the periods indicated:

~~The following table summarizes the consideration transferred to acquire New Delaware and New Midland:~~

We accounted for the Permian Acquisition as an acquisition of a business under purchase accounting rules. The assets acquired and liabilities assumed related to the Permian Acquisition were recorded at their fair values as of the closing date of March 1, 2017. The fair value of the assets acquired and liabilities assumed at the acquisition date is shown below:

Under the acquisition method of accounting, the assets acquired and liabilities assumed are recognized at their estimated fair values, with any excess of the purchase price over the estimated fair value of the identifiable net assets acquired recorded as goodwill. ~~Such excess of purchase price over the fair value of net assets acquired was approximately $46.6 million, which was recorded as goodwill. The goodwill is attributable to expected~~ ~~operational and capital synergies.~~ ~~The goodwill is amortizable for tax purposes.~~

~~The fair value of assets acquired included trade receivables of $6.7 million, substantially all of which has been subsequently collected.~~

The valuation of the acquired assets and liabilities was prepared using fair value methods and assumptions including projections of future production volumes and cash flows, benchmark analysis of comparable public companies, expectations regarding customer contracts and relationships, and other management estimates. The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs, as defined in Note 17 – Fair Value Measurements. These inputs require significant judgments and estimates at the time of valuation.

During the three months ended June 30, 2017, we recorded measurement period adjustments to our preliminary acquisition date fair values due to the refinement of our valuation models, assumptions and inputs, including forecasts of future volumes, capital expenditures and operating expenses. The measurement period adjustments were based upon information obtained about facts and circumstances that existed at the acquisition date that, if known, would have affected the measurement of the amounts recognized at that date. We recognized these measurement period adjustments in the three months ended June 30, 2017, with the effect in the Consolidated Statements of Operations resulting from the change to the provisional amounts calculated as if the acquisition had been completed at March 1, 2017. During the three months ended June 30, 2017, the acquisition date fair value of contingent consideration liability decreased by $45.3 million, intangible assets increased by $66.7 million, and other assets, net, increased by $0.4 million, which resulted in a decrease in goodwill of $112.4 million. These adjustments resulted in an increase in depreciation and amortization expense of $0.4 million recorded for the three months ended June 30, 2017.

~~During the three months ended September 30, 2017, we finalized the purchase price allocation with no additional measurement period adjustments.~~

A contingent consideration liability arising from potential earn-out payments in connection with the Permian Acquisition has been recognized at its fair value. We agreed to pay up to an additional $935.0 million in potential earn-out payments that would occur in 2018 and 2019. The acquisition date fair value of the potential earn-out payments of $416.3 million was recorded within Other long-term liabilities on our Consolidated Balance Sheets. Changes in the fair value of this liability (that were not accounted for as revisions of the acquisition date fair value) are included in earnings. During the three and nine months ended September 30, ~~2017, we recognized $126.6~~2020, depreciation expense was $168.5 million and ~~$125.5~~$538.5 million, ~~as Other income~~respectively. During the three and nine months ended September 30, 2019, depreciation expense was $201.4 million and $590.1 million, respectively.

We review and evaluate our long-lived assets, including intangible assets, for impairment when events or changes in circumstances indicate that the related carrying amount of such assets may not be recoverable, and changes to our estimates could have an impact on our assessment of asset recoverability.

During the nine months ended September 30, 2020, global commodity prices declined due to factors that significantly impacted both demand and supply. As the COVID-19 pandemic spread, causing travel and other restrictions to be implemented globally, the demand for commodities declined. Additionally, the supply shock late in the first quarter from certain major oil producing nations increasing production also significantly contributed to the ~~change~~sharp drop in commodity prices. While these major oil and gas producing countries subsequently agreed to collectively decrease production and global economies are beginning to re-open, these events, combined with the outbreak of the COVID-19 pandemic, contributed to volatility and depressed commodity prices. The drop in commodity prices resulted in prompt reactions from some domestic producers, including significantly reducing capital budgets and resultant drilling activity and shutting-in production. Commodity prices remain weak relative to historical levels and have remained volatile as uncertainty around global commodity supply and demand continues due to the COVID-19 pandemic.

In the first quarter of 2020, we determined that indicators of impairment existed for certain asset groups reported primarily within our Gathering and Processing segment. For each asset group for which undiscounted future net cash flows were not sufficient to recover the net book value, fair value was determined through use of discounted estimated cash flows to measure the impairment loss.

The estimated cash flows used to assess recoverability of our long-lived assets and measure fair value of our asset groups are derived from current business plans, which are developed using near-term price and volume projections reflective of the ~~contingent consideration. See~~current environment and management's projections for long-term average prices and volumes. In addition to near and long-term price assumptions, other key assumptions include volume projections, operating costs, timing of incurring such costs and the use of an appropriate discount rate. We believe our estimates and models used to determine fair value are similar to what a market participant would use.

~~Note 11 – Other Long-term Liabilities and Note 14 – Fair Value Measurements for additional discussion of the change in~~The fair value measurement of our long-lived assets was based, in part, on significant inputs not observable in the market (as discussed above) and ~~the fair~~thus represents a Level 3 measurement. The significant unobservable inputs used include discount rates and terminal value ~~methodology.~~

Asexit multiples. We utilized a weighted average discount rate of ~~September 30, 2017,~~14.0% when deriving the fair value of the asset groups impaired during the first ~~potential earn-out payment~~quarter of ~~$5.9 million has been recorded as~~2020. The weighted average discount rate and exit multiples reflect management’s best estimate of inputs a component of Accounts payable and accrued liabilities, which are included within current liabilities on our Consolidated Balance Sheets. As of September 30, 2017, the fair value of the second potential earn-out payment of $284.9 million has been recorded within Other long-term liabilities on our Consolidated Balance Sheets.

On May 9, 2017, we purchased all of the equity interests in Flag City Processing Partners, LLC ("FCCP") from Boardwalk Midstream, LLC (“Boardwalk”) and all of the equity interests in FCPP Pipeline, LLC from Boardwalk Field Services, LLC (“BFS”) for a base purchase price of $60.0 million subject to customary closing adjustments. The final adjustment to the base purchase price paid to Boardwalk was an additional $3.6 million. As part of the acquisition (the “Flag City Acquisition”), we acquired a natural gas processing plant with 150 MMcf/d of operating capacity (the “Flag City Plant”) located in Jackson County, Texas; 24 miles of gas gathering pipeline systems and related rights-of-ways located in Bee and Karnes counties in Texas; 102.1 acres of land surrounding the Flag City Plant; and a limited number of gas supply contracts.

The gas processing activities under the Flag City Plant contracts have been transferred to our Silver Oak Plants. We have shut down the Flag City Plant and are moving the plant and its component parts to other Targa locations.

We accounted for this purchase as an asset acquisition and have capitalized less than $0.1 million of acquisition related costs as a component of the cost of assets acquired, which resulted in an allocation of $52.3 million of property, plant and equipment, $7.7 million of intangible assets for customer contracts and $3.6 million of current assets and liabilities, net.

Effective as of June 1, 2017, we repurchased from SN Catarina, LLC (a subsidiary of Sanchez Energy Corp.) their 10% interest in our consolidated Silver Oak II Gas processing facility and other related assets located in Bee County, Texas for a purchase price of $12.5 million. The change in our ownership interest was accounted for as an equity transaction representing the acquisition of a noncontrolling interest and no gain or loss was recognized in our Consolidated Statements of Operations as a result.

Through our 76.8% ownership interest in Venice Energy Services Company, L.L.C. (“VESCO”), we have operated the Venice Gas Plant and the Venice gathering system. On April 4, 2017, VESCO entered into a purchase and sale agreement with Rosefield Pipeline Company, LLC, an affiliate of Arena Energy, LP, to sell its 100% ownership interests in Venice Gathering System, L.L.C. (“VGS”), a Delaware limited liability company engaged in the business of transporting natural gas in interstate commerce, under authorization granted by and subject to the jurisdiction of the Federal Energy Regulatory Commission (“FERC”), for approximately $0.4 million in cash. ~~Additionally, the VGS asset retirement obligations (“ARO”) were assumed by the buyer.~~ VGS owns and operates a natural gas gathering system in the Gulf of Mexico. Historically, VGS has been reported in our Gathering and Processing segment. After the sale of VGS, we continue to operate the Venice Gas Plant through our ownership in VESCO. Targa Midstream Services LLC continued to operate the Venice gathering system for four months after closing pursuant to a Transition Services Agreement with VGS.

As a result of the April 4, 2017 sale, we recognized a loss of $16.1 million in our Consolidated Statements of Operations for the three months ended March 31, 2017 as part of Other operating (income) expense to impair our basis in the VGS net assets to its fair value.

In ~~May 2017, we announced plans to construct a new common carrier NGL pipeline. The NGL pipeline (“Grand Prix”) will transport volumes from~~ the Permian Basin and our North Texas system to our fractionation and storage complex in the NGL market hub at Mont Belvieu, Texas. Grand Prix will be supported by our volumes and other third party customer commitments, and is expected to be in service in the secondfirst quarter of ~~2019. The capacity of the pipeline from the Permian Basin will be approximately 300 MBbl/d, expandable to 550 MBbl/d.~~

~~In September 2017,~~2020, we ~~sold to funds managed by Blackstone Energy Partners ("Blackstone") a 25% interest in our consolidated subsidiary, Grand Prix Pipeline LLC (the “Grand Prix Joint Venture”).We are the operator and construction manager of Grand Prix. Our share of~~ ~~total growth capital expenditures for Grand Prix is expected to be approximately $975 million, with approximately $275 million of spending in 2017.~~

Concurrent with the sale of the minority interest in the Grand Prix Joint Venture to Blackstone, we and EagleClaw Midstream Ventures, LLC (“EagleClaw”), a Blackstone portfolio company, executed a long-term Raw Product Purchase Agreement for transportation and fractionation whereby EagleClaw has dedicated and committed significant NGLs associated with EagleClaw’s natural gas volumes produced or processed in the Delaware Basin.

We recorded a non-cash pre-tax ~~impairment charge~~impairments of ~~$378.0~~$2,442.8 million ~~in the third quarter of 2017 for~~primarily associated with the partial impairment of gas processing facilities and gathering systems associated with our ~~North Texas~~Mid-Continent operations and full impairment of our Coastal operations - all of which are in our Gathering and Processing segment. ~~The~~Our first quarter impairment ~~is a result of our current~~ assessment ~~that~~ forecasted undiscounted future net cash flows from operations, while positive, will not be sufficient to recover the existing total net book value of the underlying assets. Given the current price environment, Targa is projecting a continuingfurther decline in natural gas production across the ~~Barnett Shale in North Texas due in part to producers pursuing more attractive opportunities in other basins. We measured the impairment~~Mid-Continent and Gulf of ~~property, plant and equipment using discounted estimated future cash flow analysis (“DCF”) including a terminal value (a Level 3 fair value measurement).~~Mexico. The future cash flows are based on our estimates of future revenues, income from operations and other factors, such as timing of capital expenditures. We take into account current and expected industry and market conditions, including commodity prices and volumetric forecasts. The discount rate used in our DCF analysis is based on a weighted average cost of capital determined from relevant market comparisons. These carrying value adjustments are included in Impairment of ~~property, plant and equipment expense~~long-lived assets in our Consolidated Statements of Operations.There were no indicators of impairment identified during the second or third quarters of 2020.

Intangible assets consist of customer contracts and customer relationships acquired in the Permian and Flag City Acquisitions in 2017, the mergers with Atlas Energy L.P. and Atlas Pipeline Partners L.P. in 2015 (collectively, the “Atlas mergers”) and our Badlands acquisition in 2012.prior business combinations. The fair ~~values~~value of these acquired intangible assets were determined at the date of acquisition based on the present values of estimated future cash flows. Key valuation assumptions include probability of contracts under negotiation, renewals of existing contracts, economic incentives to retain customers, past and future volumes, current and future capacity of the gathering

~~system, pricing volatility and the discount rate.~~ Amortization expense attributable to these assets is recorded over the periods in which we benefit from services provided to customers.

As a result of the triggering events and analysis described above, in the ~~Permian Acquisition~~first quarter of 2020, we recognized a non-cash pre-tax impairment loss associated with certain intangible customer relationships for which undiscounted future net cash flows were ~~recorded at a fair value of $692.3 million. We are amortizing these intangible assets over a 15-year life using~~not sufficient to recover the ~~straight-line method.~~

~~The intangible assets acquired in the Flag City Acquisition were recorded at a fair value of $7.7 million. We are amortizing these intangible assets over a 10-year life using the straight-line method.~~

The intangible assets acquired in the Atlas mergers are being amortized over a 20-year life using the straight-line method, as a reliably determinable pattern of amortization could not be identified. Amortization expense attributable to our intangible assets related to the Badlands acquisition is recorded using a method that closely reflects the cash flow pattern underlying their intangible asset valuation over a 20-year life.net book value.

The estimated annual amortization expense for intangible assets is approximately ~~$188.4~~$144.0 million, ~~$182.6~~$130.9 million, ~~$171.6~~$122.7 million, ~~$159.4~~$117.5 million and ~~$149.5~~$113.7 million for each of the years ~~2017~~2020 through ~~2021.~~2024, respectively.

In October 2020, we executed agreements to sell our assets in Channelview, Texas for approximately $58 million (the “October 2020 Sale”). As ~~described in Note~~of September 30, 2020, we classified our assets as held for sale and measured the fair value of the disposal group using the expected sales price under a contract with a third party (an input within Level 3 – Significant Accounting Policies, we evaluate goodwill for impairment at least annually on November 30, or more frequently if we believe necessary based on events or changes in circumstances. Duringof the ~~first quarter~~fair value hierarchy). We recognized a loss of ~~2016, we finalized our 2015 impairment assessment and recorded additional impairment~~$58.3 million included within Other operating (income) expense ~~of $24.0 million~~ in our Consolidated ~~Statement~~Statements of ~~Operations. The impairment of goodwill was primarily due~~Operations for the three and nine months ended September 30, 2020 to reduce the ~~effects of lower commodity prices, and a higher cost of capital for companies in our industry compared to conditions in February 2015 when we acquired Atlas.~~

~~Changes in the net book~~carrying value of our ~~goodwill~~assets to their recoverable amounts.

The sale closed in October 2020, and we used the proceeds for general corporate purposes. The sale of the assets is included in our Logistics and Transportation segment and does not qualify for reporting as a discontinued operation, as its divestiture did not represent a strategic shift that would have a major effect on our operations or financial results.

The adjusted carrying amounts of the assets and liabilities held for sale as of September 30, 2020 are as follows:

~~Our investments in unconsolidated affiliates consist of the following:~~5 — Debt Obligations

The terms of these joint venture agreements do not afford us the degree of control required for consolidating them in our consolidated financial statements, but do afford us the significant influence required to employ the equity method of accounting.

The T2 Joint Ventures were formed to provide services for the benefit of its joint interest owners. The T2 LaSalle and T2 Eagle Ford gathering companies have capacity lease agreements with its joint interest owners, which cover costs of operations (excluding depreciation and amortization).

~~In July 2017, we entered into the Cayenne~~ ~~Joint Venture~~ with American Midstream LLC to convert an existing 62-mile gas pipeline to an NGL pipeline connecting the VESCO plant in Venice, Louisiana to the Enterprise Products Operating LLC (“Enterprise”) pipeline

~~at Toca, Louisiana, for delivery to Enterprise’s Norco Fractionator. We acquired a 50% interest in the Cayenne~~ ~~Joint Venture for $5.0 million. The project is expected to be completed by November 2017.~~

~~The following table shows the activity related to our investments in unconsolidated affiliates:~~

GCF

T2 LaSalle

T2 Eagle Ford

T2 EF Cogen

Cayenne

Total

Balance at December 31, 2016

$
46.1

$
58.6

$
118.6

$
17.5

$
—

$
240.8

Equity earnings (loss)

8.4

(3.7
)

(7.9
)

(13.4
)

—

(16.6
)
Cash distributions (1)

(10.6
)

—

—

—

—

(10.6
)
Acquisition

—

—

—

—

5.0

5.0

Contributions (2)

—

0.4

1.2

0.1

1.8

3.5

Balance at September 30, 2017

$
43.9

$
55.3

$
111.9

$
4.2

$
6.8

$
222.1

	September 30, 2020			December 31, 2019
Current:
Accounts receivable securitization facility, due April 2021 (1)	$	250.0		$	370.0
Finance lease liabilities		11.9			12.2
Current debt obligations		261.9			382.2

Long-term:
Senior secured revolving credit facility, variable rate, due June 2023 (2)		100.0			—
Senior unsecured notes:
5¼% fixed rate, due May 2023		559.6			559.6
4¼% fixed rate, due November 2023		583.9			583.9
6¾% fixed rate, due March 2024		—			580.1
5⅛% fixed rate, due February 2025		481.0			500.0
5⅞% fixed rate, due April 2026		963.2			1,000.0
5⅜% fixed rate, due February 2027		468.1			500.0
6½% fixed rate, due July 2027		705.2			750.0
5% fixed rate, due January 2028		700.3			750.0
6⅞% fixed rate, due January 2029		679.3			750.0
5½% fixed rate, due March 2030		949.6			1,000.0
4⅞% fixed rate, due February 2031		1,000.0			—
TPL notes, 4¾% fixed rate, due November 2021 (3)		6.5			6.5
TPL notes, 5⅞% fixed rate, due August 2023 (3)		48.1			48.1
Unamortized premium		0.2			0.3
		7,245.0			7,028.5
Debt issuance costs, net of amortization		(48.5	)		(49.1	)
Finance lease liabilities		20.7			25.8
Long-term debt		7,217.2			7,005.2
Total debt obligations	$	7,479.1		$	7,387.4
Irrevocable standby letters of credit outstanding (2)	$	35.3		$	88.2

~~(2) Includes a $1.0 million contribution of property, plant and equipment to T2 Eagle Ford.~~

Our equity loss for the nine months ended September 30, 2017 includes the effect of an impairment in the carrying value of our investment in T2 EF Cogen. As a result of the decrease in current and expected future utilization of the underlying cogeneration assets, we have determined that factors indicate that a decrease in the value of our investment occurred that was other than temporary. As a result of this evaluation, we recorded an impairment loss of approximately $12.0 million in the first quarter of 2017, which represented our proportionate share (50%) of an impairment charge recorded by the joint venture, as well as our impairment of the unamortized excess fair value resulting from the Atlas mergers.

~~The carrying values of the T2~~ ~~Joint Venture~~s include the effects of the Atlas mergers purchase accounting, which determined fair values for the joint ventures as of the date of acquisition. As of September 30, 2017, $26.8 million of unamortized excess fair value over the T2 LaSalle and T2 Eagle Ford capital accounts remained. These basis differences, which are attributable to the underlying depreciable tangible gathering assets, are being amortized on a straight-line basis as components of equity earnings over the estimated 20-year useful lives of the underlying assets.

In October 2017, we announced that we had executed a letter of intent along with Kinder Morgan Texas Pipeline LLC (“KMTP”) and DCP Midstream Partners, LP with respect to the joint development of the proposed Gulf Coast Express Pipeline Project (“GCX Project”), which would provide an outlet for increased natural gas production from the Permian Basin to growing markets along the Texas Gulf Coast. Under the terms of the letter of intent, we would own a 25% interest in the GCX Project. KMTP would serve as the operator and constructor of the GCX Project, and we would commit significant volumes to it, including certain volumes provided by Pioneer Natural Resources Company, a joint owner in our WestTX Permian Basin system. The participation of the three parties involved with GCX Project is subject to negotiation and execution of definitive agreements.

Accounts payable and accrued liabilities includes $29.2 million and $30.2 million of liabilities to creditors to whom we have issued checks that remained outstanding as of September 30, 2017 and December 31, 2016. The estimated current portion of the Permian Acquisition contingent consideration represents the fair value as of September 30, 2017 of the first potential earn-out payment that would be payable in May 2018. The estimated remaining portion would be payable in May 2019 and is recorded within Other long-term liabilities on our Consolidated Balance Sheets.

The following table shows the range of interest rates and weighted average interest rate incurred on ~~our~~ variable-rate debt obligations during the nine months ended September 30, ~~2017:~~

As of September 30, ~~2017,~~2020, we were in compliance with the covenants contained in our various debt agreements.

~~On February 23, 2017,~~In August 2020, we ~~amended~~issued $1.0 billion aggregate principal amount of 4⅞% Senior Notes due 2031 (the “August 2020 Offering”), resulting in net proceeds of $991.0 million. The 4⅞% Senior Notes due 2031 have substantially similar terms and covenants as our other series of Senior Notes. A portion of the ~~accounts receivable securitization facility (“Securitization Facility”~~net proceeds from the issuance were used to fund the concurrent cash tender offer (the “Tender Offer”) ~~to increase~~of our 6¾% Senior Notes due 2024 and redeem any 6¾% Senior Notes due 2024 that remained outstanding after consummation of the ~~facility size from $275.0 million to $350.0 million. As~~Tender Offer, with the remainder used for repayment of ~~September 30, 2017, there was $278.1 million outstanding~~borrowings under the ~~Securitization Facility.~~TRP Revolver. See “Debt Extinguishments and Repurchases” for further details of the concurrent tender offer.

~~In June 2017,~~Concurrent with the August 2020 Offering, we ~~redeemed~~commenced the Tender Offer to purchase for cash, subject to certain terms and conditions, any and all of our outstanding 6⅜6¾% Senior Notes due 2024. We accepted for purchase all the notes that were validly tendered as of the early tender date, which totaled $262.1 million.

Subsequent to the closing of the Tender Offer in August ~~2022 (“6⅜~~2020, we redeemed the 6¾% Senior ~~Notes”), totaling $278.7~~Notes due 2024 for the remaining note balance of $318.0 million ~~in aggregate principal amount, at~~(the “2024 Note Redemption”). As a ~~price~~result of ~~103.188% plus accrued interest through~~ the ~~redemption date. The redemption resulted in~~Tender Offer and the 2024 Note Redemption, we recorded a ~~$10.7~~loss due to debt extinguishment of $13.7 million ~~loss, which is reflected as Loss from financing activities in the Consolidated Statements~~comprised of ~~Operations, consisting of~~$11.1 million premiums paid ~~of $8.9 million~~ and a ~~non-cash loss to~~ write-off ~~$1.8~~of $2.6 million of ~~unamortized~~ debt issuance costs.

The following table summarizes our senior note repurchases for the nine months ended September 30, 2020:

We may retire or purchase various series of our outstanding debt through cash purchases and/or exchanges for other debt, in open market purchases, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.

The following table summarizes payment obligations for debt instruments after giving effect to the debt repurchases detailed above:

(1)Represents scheduled future maturities of consolidated debt obligations for the periods indicated.

(2)Represents interest expense on debt obligations based on both fixed debt interest rates and prevailing September 30, 2020 rates for floating debt.

On November 2, 2020, we ~~issued $750.0~~redeemed the $559.6 million ~~aggregate principal amount~~remaining balance of ~~5% senior notes due January 2028 (the “5%~~our 5¼% Senior Notes due 2028”). We used the net proceeds of $744.4 million after costs from this offering to redeem our 5% Senior Notes due 2018, reduce borrowings under our credit facilities, and for general partnership purposes.2023.

~~In October 2017, we redeemed our outstanding~~ ~~5% Senior Notes due 2018 at par value~~ plus accrued interest through the redemption date. The redemption resulted in a non-cash Loss from financing activities to write-off $0.2 million of unamortized debt issuance costs in the fourth quarter of 2017.

~~Our ARO primarily relate to certain gas gathering pipelines~~deferred revenue, asset retirement obligations and ~~processing facilities. The changes in our ARO are as follows:~~

Our consolidated financial statements include our interest in two joint ventures that, separately, own a 100% interest in the WestOK natural gas gathering and processing system and a 72.8% undivided interest in the WestTX natural gas gathering and processing system. Our partner in the joint ventures holds preferred interests in each joint venture that are redeemable: (i) at our or our partner’s election, on or after July 27, 2022; and (ii) mandatorily, in July 2037.

For reporting purposes under GAAP, an estimate of our partner’s interest in each joint venture is required to be recorded as if the redemption had occurred on the reporting date. Because redemption cannot occur before 2022, the actual value of our partner’s allocable share of each joint venture’s assets at the time of redemption may differ from our estimate of redemption value as of September 30, 2017.

~~The following table shows the changes attributable to mandatorily redeemable preferred interests:~~

We have certain long-term contractual arrangements ~~under~~for which we have received consideration ~~but which require future performance by Targa. These arrangements result in~~that we are not yet able to recognize as revenue. The resulting deferred revenue ~~which~~ will be recognized ~~over the periods that performance will be provided.~~once all conditions for revenue recognition have been met.

Deferred revenue as of September 30, 2020 and December 31, 2019, was $169.4 million and $172.0 million, respectively, which includes ~~consideration~~$129.0 million of payments received from Vitol Americas Corp. (“Vitol”) (formerly known as Noble Americas Corp.), a subsidiary of Vitol US Holding Co., in 2016, 2017, and 2018 as part of an agreement (the “Splitter Agreement”) related to the construction and operation of a crude oil and condensate splitter. OnIn December 27, 2015, Targa Terminals LLC and Noble Americas Corp., a subsidiary of Noble Group Ltd., entered into a long-term, fee-based agreement (“Splitter Agreement”) under which we will build and operate a crude oil and condensate splitter at our Channelview Terminal on the Houston Ship Channel (“Channelview Splitter”) and provide approximately 730,000 barrels of storage capacity. The Channelview Splitter will have the capability2018, Vitol elected to split approximately 35,000 barrels per day of crude oil and condensate into its various components, including naphtha, kerosene, gas oil, jet fuel, and liquefied petroleum gas and will provide segregated storage for the crude, condensate and components. The Channelview Splitter project is expected to be completed by the first half of 2018, and has an estimated total cost of approximately $140.0 million. The first annual advance payment due underterminate the Splitter ~~Agreement was received in October 2016 and has been recorded as deferred revenue, as the Splitter Agreement~~ ~~requires future performance by Targa.~~Agreement. The Splitter Agreement provides that ~~subsequent~~the first three annual payments are ours if Vitol elects to terminate, which Vitol disputes. The timing of ~~$43.0 million (subject~~revenue recognition related to ~~an annual inflation factor) are to be paid to Targa through 2022. In October 2017, we received $43.0 million representing the second annual payment under~~ the Splitter Agreement ~~which will be recorded as deferred revenue. The~~ deferred revenue ~~receipts will be recognized over~~is dependent on the ~~contractual period that future performance will be provided, currently anticipated to commence~~outcome of current litigation with ~~start-up in 2018 and continuing through 2025.~~

Vitol. Deferred revenue also includes nonmonetary consideration received in a 2015 amendment ~~(the “gas contract amendment”)~~ to a gas gathering and processing agreement. We measured the estimated fair value of the gathering assets transferred to us using significant other observable inputs representative of a Level 2 fair value measurement. Because the gas contract amendment will require future performance by Targa, we have recorded the consideration received as deferred revenue. The deferred revenue related to this amendment is being recognized on a straight-line basis through the end of the agreement’s term in 2030.

~~Deferred revenue also includes~~agreement and consideration received for other construction activities of facilities connected to our systems. ~~The deferred revenue~~See Part II—Item 1. Legal Proceedings for further details on the related ~~to these other construction activities will be recognized over the periods that future performance will be provided, which extend through 2023.~~litigation.

Upon closing of the Permian Acquisition, a contingent consideration liability arising from potential earn-out provisions was recognized at its preliminary fair value. The potential earn-out payments will be based upon a multiple of gross margin realized ~~during the first two annual periods after the acquisition date~~ from contracts that existed on March 1, 2017. The first potential earn-out payment would occur in May 2018 and the second potential earn-out payment would occur in May 2019. The preliminary acquisition date fair value of the contingent consideration of $461.6 million was recorded within Other long-term liabilities on our Consolidated Balance Sheets as of March 31, 2017. Subsequent changes in the fair value of the contingent consideration that were not accounted for as revisions (measurement period adjustments) to the acquisition date fair value have been included in Other income (expense).

During the three months ended June 30, 2017, we recognized certain adjustments that were accounted for as revisions to the acquisition date fair value and decreased the acquisition date fair value of the contingent consideration by $45.3 million to $416.3

~~million. During the three months ended September 30, 2017, we finalized the purchase price allocation with no additional revisions to the acquisition date fair value. See~~ Note ~~4 – Acquisitions and Divestments for additional discussion.~~

For the period from the acquisition date to September 30, 2017, the fair value of this liability decreased by $125.5 million, bringing the total Permian Acquisition contingent consideration to $290.8 million at September 30, 2017. The decrease in fair value of the contingent consideration was primarily related to reductions in actual and forecasted volumes and gross margin as a result of changes in producers’ drilling activity in the region since the acquisition date. Such changes in estimated fair value of the contingent consideration are attributable to events and circumstances that occurred after the acquisition date, and as such have been recognized in Other income (expense).

As of September 30, 2017, the fair value of the first potential earn-out payment of $5.9 million has been recorded as a component of Accounts payable and accrued liabilities, which are current liabilities on our Consolidated Balance Sheets. As of September 30, 2017, the fair value of the second potential earn-out payment of $284.9 million has been recorded within Other long-term liabilities on our Consolidated Balance Sheets. See Note 14 – Fair Value Measurements for additional discussion of the fair value methodology.

TRC is entitled to receive all Partnership distributions ~~from available cash on the Partnership’s common units~~ after payment of preferred ~~units~~unit distributions each quarter. ~~We have discretion under~~ ~~the Third A&R Partnership Agreement~~ ~~as to whether to distribute all available cash for any period.~~ ~~See Note 1 – Organization and Operations.~~

The following table details the distributions declared orand paid by us for the nine months ended September 30, ~~2017:~~2020:

~~Subsequent to December 1, 2016, the effective date of the Third A&R Partnership Agreement, no units will be issued for~~

All capital contributions to us ~~but all capital contributions will~~ continue to be allocated 98% to the limited partner and 2% to ~~the~~our general ~~partner.~~partner; however, 0 units will be issued for those contributions. For the nine months ended September 30, ~~2017,~~2020, TRC made a total ~~capital~~of $50.0 million in contributions to ~~us of $1,620.0 million.~~ us.

~~In October 2015, we completed an offering of 5,000,000~~Our Preferred Units ~~at a price of $25.00 per unit. The Preferred Units are listed on the NYSE under the symbol “NGLS PRA.”~~

At any time on or after November 1, 2020, we may redeem the Preferred Units, in whole or in part, from any source of funds legally available for such purpose, by paying $25.00 per unit plus an amount equalrank senior to ~~all accumulated and unpaid distributions thereon~~our common units with respect to the date of redemption, whether or not declared. In addition, we (or a third party with our prior written consent) may redeem the Preferred Units following certain changes of control, as described in our Partnership Agreement. Holders of Preferred Units have no voting rights except for certain exceptions set forth in our Partnership Agreement.

distribution rights. Distributions on our 5,000,000 Preferred Units are cumulative from the date of original issue in October 2015 and are payable monthly in arrears on the 15th day of each month of each year, when, as and if declared by the board of directors of our general partner. Distributions on

our Preferred Units are payable out of amounts legally available at a rate equal to 9.0% per annum. On and after November 1, 2020, distributions on our Preferred Units will accumulate at an annual floating rate equal to the one-month LIBOR plus a spread of 7.71%.

We paid $2.8 million and $8.4 million of distributions to the holders of ~~preferred units~~Preferred Units (“Preferred Unitholders”) ~~during~~for the three and nine months ended September 30, ~~2017. The Preferred Units are reported as noncontrolling interests in our financial statements.~~2020.

In October ~~2017,~~2020, the board of directors of our general partner declared a cash distribution of $0.1875 per Preferred ~~Unit. This distribution~~Unit, resulting in approximately $0.9 million in distributions that will be paid on November ~~15, 2017.~~16, 2020.

The primary ~~purpose~~purposes of our commodity risk management activities isare to manage our exposure to commodity price risk and reduce volatility in our operating cash flow due to fluctuations in commodity prices. We have ~~hedged~~entered into derivative instruments to hedge the commodity ~~prices~~price risks associated with a portion of our expected (i) natural gas, NGL, and condensate equity volumes in our Gathering and Processing operations that result from percent-of-proceeds processing arrangements, ~~and~~ (ii) future commodity purchases and sales in our Logistics and ~~Marketing~~Transportation segment ~~by entering into derivative instruments. These~~and (iii) natural gas transportation basis risk in our Logistics and Transportation segment. The hedge positions associated with (i) and (ii) above will move favorably in periods of falling commodity prices and unfavorably in periods of rising commodity ~~prices. We have~~prices and are designated ~~these derivative contracts~~ as cash flow hedges for accounting purposes.

The hedges generally match the NGL product composition and the NGL delivery points of our physical equity volumes. Our natural gas hedges are a mixture of specific gas delivery points and Henry Hub. The NGL hedges may be transacted as specific NGL hedges or as baskets of ethane, propane, normal butane, isobutane and natural gasoline based upon our expected equity NGL composition. We believe this approach avoids uncorrelated risks resulting from employing hedges on crude oil or other petroleum products as “proxy” hedges of NGL prices. Our natural gas and NGL hedges are settled using published index prices for delivery at various locations.

We hedge a portion of our condensate equity volumes using crude oil hedges that are based on the NYMEX futures contracts for West Texas Intermediate light, sweet crude, which approximates the prices received for condensate. This exposes us to a market differential risk if the NYMEX futures do not move in exact parity with the sales price of our underlying condensate equity volumes.

As part of the Atlas mergers, outstanding TPL derivative contracts with a fair value of $102.1 million as of February 27, 2015 (the “acquisition date”), were novated to us and included in the acquisition date fair value of assets acquired. We received derivative settlements of $1.4 million and $6.3 million for the three and nine months ended September 30, 2017 and $5.8 million and $20.9 million for the three and nine months ended September 30, 2016, related to these novated contracts. From the acquisition date through September 30, 2017, we have received derivative settlements of $100.9 million. ~~The remainder of the novated contracts will settle by the end of 2017.~~ ~~These settlements were reflected as a reduction of the acquisition date fair value of the TPL derivative assets acquired and had no effect on results of operations.~~

The "off-market" nature of these acquired derivatives can introduce a degree of ineffectiveness for accounting purposes due to an embedded financing element representing the amount that would be paid or received as of the acquisition date to settle the derivative contract. The resulting ineffectiveness can either potentially disqualify the derivative contract in its entirety for hedge accounting or alternatively affect the amount of unrealized gains or losses on qualifying derivatives that can be deferred from inclusion in periodic net income. Additionally, we recorded ineffectiveness losses of less than $0.1 million and $0.1 million for the three and nine months ended September 30, 2017 and less than $0.1 million and $0.3 million for the three and nine months ended September 30, 2016, related to otherwise qualifying TPL derivatives, which are primarily natural gas swaps.

We also enter into derivative instruments to help manage other short-term commodity-related business risks. We have not designated these derivatives as hedges and record changes in fair value and cash settlements to revenues.

At September 30, ~~2017,~~2020, the notional volumes of our commodity derivative contracts were:

Commodity	Instrument	Unit	2017		2018		2019		2020		Instrument	Unit	2020		2021		2022		2023		2024		2025
Natural Gas	Swaps	MMBtu/d		160,347		151,100		116,136		-
Natural Gas	Basis Swaps	MMBtu/d		92,200		15,726		12,500		10,445
Natural Gas	Futures	MMBtu/d		-		1,103		-		-	Swaps	MMBtu/d		168,317		166,216		90,600		33,350		0		0
Natural Gas	Options	MMBtu/d		22,900		9,486		-		-	Basis Swaps	MMBtu/d		445,084		471,168		295,390		250,000		90,000		5,000
NGL	Swaps	Bbl/d		23,432		12,858		7,399		-	Swaps	Bbl/d		30,909		29,261		16,848		2,627		0		0
NGL	Futures	Bbl/d		38,880		6,589		329		-	Futures	Bbl/d		52,685		25,526		0		0		0		0
NGL	Options	Bbl/d		3,094		2,986		410		-
Condensate	Swaps	Bbl/d		3,150		2,420		1,293		-	Swaps	Bbl/d		5,190		4,872		2,125		515		0		0
Condensate	Options	Bbl/d		1,380		691		590		-

Our derivative contracts are subject to netting arrangements that permit our contracting subsidiaries to net cash settle offsetting asset and liability positions with the same counterparty within the same Targa entity. We record derivative assets and liabilities on our Consolidated Balance Sheets on a gross basis, without considering the effect of master netting arrangements. The following schedules reflect the fair ~~values~~value of our derivative instruments and their location on our Consolidated Balance Sheets as well as pro forma reporting assuming that we reported derivatives subject to master netting agreements on a net basis:

		Fair Value as of September 30, 2017				Fair Value as of December 31, 2016					Fair Value as of September 30, 2020				Fair Value as of December 31, 2019
	Balance Sheet	Derivative		Derivative		Derivative		Derivative		Balance Sheet	Derivative		Derivative		Derivative		Derivative
	Location	Assets		Liabilities		Assets		Liabilities		Location	Assets		Liabilities		Assets		Liabilities
Derivatives designated as hedging instruments
Commodity contracts	Current	$	18.4	$	79.9	$	16.7	$	48.6	Current	$	58.4	$	116.1	$	102.1	$	11.6
	Long-term		13.7		14.4		5.1		26.1	Long-term		14.0		62.8		33.7		6.4
Total derivatives designated as hedging instruments		$	32.1	$	94.3	$	21.8	$	74.7		$	72.4	$	178.9	$	135.8	$	18.0
Derivatives not designated as hedging instruments
Commodity contracts	Current	$	0.3	$	1.0	$	0.1	$	0.5	Current	$	30.5	$	5.0	$	1.2	$	92.5
	Long-term		-		0.5		-		-	Long-term		65.5		0.1		1.8		34.4
Total derivatives not designated as hedging instruments		$	0.3	$	1.5	$	0.1	$	0.5		$	96.0	$	5.1	$	3.0	$	126.9
Total current position		$	18.7	$	80.9	$	16.8	$	49.1		$	88.9	$	121.1	$	103.3	$	104.1
Total long-term position			13.7		14.9		5.1		26.1			79.5		62.9		35.5		40.8
Total derivatives		$	32.4	$	95.8	$	21.9	$	75.2		$	168.4	$	184.0	$	138.8	$	144.9

The pro forma impact of reporting derivatives on our Consolidated Balance Sheets on a net basis is as follows:

		Gross Presentation							Pro forma net presentation						Gross Presentation								Pro Forma Net Presentation
September 30, 2017		Asset		Liability			Collateral		Asset		Liability
September 30, 2020														September 30, 2020	Asset		Liability			Collateral			Asset		Liability
Current Position	Current Position													Current Position
	Counterparties with offsetting positions or collateral	$	18.7	$	(79.5	)	$	44.6	$	3.6	$	(19.8	)	Counterparties with offsetting positions or collateral	$	80.3	$	(121.1	)	$	60.1		$	31.5	$	(12.2	)
	Counterparties without offsetting positions - assets		-		-			-		-		-		Counterparties without offsetting positions - assets		8.6		-			-			8.6		-
	Counterparties without offsetting positions - liabilities		-		(1.4	)		-		-		(1.4	)	Counterparties without offsetting positions - liabilities		-		-			-			-		-
			18.7		(80.9	)		44.6		3.6		(21.2	)			88.9		(121.1	)		60.1			40.1		(12.2	)
Long Term Position	Long Term Position													Long Term Position
	Counterparties with offsetting positions or collateral		13.5		(14.2	)		-		6.5		(7.2	)	Counterparties with offsetting positions or collateral		63.4		(62.6	)		-			26.3		(25.5	)
	Counterparties without offsetting positions - assets		0.2		-			-		0.2		-		Counterparties without offsetting positions - assets		16.1		-			-			16.1		-
	Counterparties without offsetting positions - liabilities		-		(0.7	)		-		-		(0.7	)	Counterparties without offsetting positions - liabilities		-		(0.3	)		-			-		(0.3	)
			13.7		(14.9	)		-		6.7		(7.9	)			79.5		(62.9	)		-			42.4		(25.8	)
Total Derivatives	Total Derivatives													Total Derivatives
	Counterparties with offsetting positions or collateral		32.2		(93.7	)		44.6		10.1		(27.0	)	Counterparties with offsetting positions or collateral		143.7		(183.7	)		60.1			57.8		(37.7	)
	Counterparties without offsetting positions - assets		0.2		-			-		0.2		-		Counterparties without offsetting positions - assets		24.7		-			-			24.7		-
	Counterparties without offsetting positions - liabilities		-		(2.1	)		-		-		(2.1	)	Counterparties without offsetting positions - liabilities		-		(0.3	)		-			-		(0.3	)
		$	32.4	$	(95.8	)	$	44.6	$	10.3	$	(29.1	)		$	168.4	$	(184.0	)	$	60.1		$	82.5	$	(38.0	)

		Gross Presentation							Pro forma net presentation						Gross Presentation								Pro Forma Net Presentation
December 31, 2016		Asset		Liability			Collateral		Asset		Liability
December 31, 2019														December 31, 2019	Asset		Liability			Collateral			Asset		Liability
Current Position	Current Position													Current Position
	Counterparties with offsetting positions or collateral	$	16.8	$	(46.1	)	$	7.0	$	5.7	$	(28.0	)	Counterparties with offsetting positions or collateral	$	99.8	$	(85.0	)	$	(4.9	)	$	56.0	$	(46.1	)
	Counterparties without offsetting positions - assets		-		-			-		-		-		Counterparties without offsetting positions - assets		3.5		-			-			3.5		-
	Counterparties without offsetting positions - liabilities		-		(3.0	)		-		-		(3.0	)	Counterparties without offsetting positions - liabilities		-		(19.1	)		-			-		(19.1	)
			16.8		(49.1	)		7.0		5.7		(31.0	)			103.3		(104.1	)		(4.9	)		59.5		(65.2	)
Long Term Position	Long Term Position													Long Term Position
	Counterparties with offsetting positions or collateral		5.1		(18.7	)		-		-		(13.6	)	Counterparties with offsetting positions or collateral		33.3		(40.5	)		-			18.1		(25.3	)
	Counterparties without offsetting positions - assets		-		-			-		-		-		Counterparties without offsetting positions - assets		2.2		-			-			2.2		-
	Counterparties without offsetting positions - liabilities		-		(7.4	)		-		-		(7.4	)	Counterparties without offsetting positions - liabilities		-		(0.3	)		-			-		(0.3	)
			5.1		(26.1	)		-		-		(21.0	)			35.5		(40.8	)		-			20.3		(25.6	)
Total Derivatives	Total Derivatives													Total Derivatives
	Counterparties with offsetting positions or collateral		21.9		(64.8	)		7.0		5.7		(41.6	)	Counterparties with offsetting positions or collateral		133.1		(125.5	)		(4.9	)		74.1		(71.4	)
	Counterparties without offsetting positions - assets		-		-			-		-		-		Counterparties without offsetting positions - assets		5.7		-			-			5.7		-
	Counterparties without offsetting positions - liabilities		-		(10.4	)		-		-		(10.4	)	Counterparties without offsetting positions - liabilities		-		(19.4	)		-			-		(19.4	)
		$	21.9	$	(75.2	)	$	7.0	$	5.7	$	(52.0	)		$	138.8	$	(144.9	)	$	(4.9	)	$	79.8	$	(90.8	)

Our payment obligations in connection with a majority of these hedging transactions are secured by a first priority lien in the collateral securing the TRP Revolver that ranks equal in right of payment with liens granted in favor of our senior secured lenders. Some of our hedges are futures contracts executed through ~~a broker~~brokers that ~~clears~~clear the hedges through an exchange. We maintain a margin deposit with the ~~broker~~brokers in an amount sufficient enough to cover the fair value of our open futures positions. The margin deposit is considered collateral, which is located within ~~other current assets~~Deposits on our Consolidated Balance Sheets and is not offset against the fair ~~values~~value of our derivative instruments.

The fair value of our derivative instruments, depending on the type of instrument, was determined by the use of present value methods or standard option valuation models with assumptions about commodity prices based on those observed in underlying markets. The estimated fair value of our derivative instruments was a net liability of ~~$63.4~~$15.6 million as of September 30, ~~2017.~~2020. The estimated fair value is net of an adjustment for credit risk based on the default probabilities as indicated by market quotes for the counterparties’ credit default swap rates. The credit risk adjustment was immaterial for all periods presented. Our futures contracts that are cleared through an exchange are margined daily and do not require any credit adjustment.

The following tables reflect amounts recorded in Other ~~Comprehensive Income~~comprehensive income (“OCI”) and amounts reclassified from OCI to revenue ~~and expense~~ for the periods indicated:

	Gain (Loss) Recognized in OCI on Derivatives (Effective Portion)											Gain (Loss) Recognized in OCI on Derivatives (Effective Portion)
Derivatives in Cash Flow	Three Months Ended September 30,					Nine Months Ended September 30,						Three Months Ended September 30,					Nine Months Ended September 30,
Hedging Relationships	2017			2016		2017			2016			2020			2019		2020			2019
Commodity contracts	$	(106.8	)	$	12.9	$	(10.5	)	$	(40.5	)	$	(128.7	)	$	118.2	$	(102.6	)	$	167.8

	Gain (Loss) Reclassified from OCI into Income (Effective Portion)										Gain (Loss) Reclassified from OCI into Income (Effective Portion)
	Three Months Ended September 30,					Nine Months Ended September 30,					Three Months Ended September 30,				Nine Months Ended September 30,
Location of Gain (Loss)	2017			2016		2017			2016		2020		2019		2020		2019
Revenues	$	(2.1	)	$	8.1	$	(2.2	)	$	50.6	$	19.2	$	41.5	$	139.4	$	106.1

Based on valuations as of September 30, 2020, we expect to reclassify commodity hedge-related deferred losses of $(106.0) million included in accumulated other comprehensive income into earnings before income taxes through the end of 2023, with $(57.2) million of losses to be reclassified over the next twelve months.

Our consolidated earnings are also affected by the use of the mark-to-market method of accounting for derivative instruments that do not qualify for hedge accounting or that have not been designated as hedges. The changes in fair value of these instruments are recorded on the balance sheet and through earnings rather than being deferred until the anticipated transaction settles. The use of mark-to-market accounting for financial instruments can cause non-cash earnings volatility due to changes in the underlying commodity price indices. For the three and nine months ended September 30, 2020, the unrealized mark-to-market gains are primarily attributable to favorable movements in natural gas forward basis prices, as compared to our hedged positions.

	Location of Gain	Gain (Loss) Recognized in Income on Derivatives											Location of Gain	Gain (Loss) Recognized in Income on Derivatives
Derivatives Not Designated	Recognized in Income on	Three Months Ended September 30,						Nine Months Ended September 30,					Recognized in Income on	Three Months Ended September 30,					Nine Months Ended September 30,
as Hedging Instruments	Derivatives	2017			2016			2017			2016		Derivatives	2020		2019			2020		2019
Commodity contracts	Revenue	$	(1.5	)	$	(0.3	)	$	(2.9	)	$	1.3	Revenue	$	90.0	$	(103.3	)	$	197.9	$	(113.8	)

Based on valuations as of September 30, 2017, we expect to reclassify commodity hedge-related deferred losses of $64.1 million included in accumulated other comprehensive income into earnings before income taxes through the end of 2019, with $63.0 million of losses to be reclassified over the next twelve months.

See Note 149 – Fair Value Measurements and Note 15 – Segment Information for additional disclosures related to derivative instruments and hedging activities.

Under GAAP, our Consolidated Balance Sheets reflect a mixture of measurement methods for financial assets and liabilities (“financial instruments”). Derivative financial instruments and contingent consideration related to business acquisitions are reported at fair value on our Consolidated Balance Sheets. Other financial instruments are reported at historical cost or amortized cost on our Consolidated Balance Sheets. The following are additional qualitative and quantitative disclosures regarding fair value measurements of financial instruments.

Our derivative instruments consist of financially settled commodity swaps, futures, option contracts and fixed-price forward commodity contracts with certain counterparties. We determine the fair value of our derivative contracts using present value methods or standard option valuation models with assumptions about commodity prices based on those observed in underlying markets. We have consistently applied these valuation techniques in all periods presented and we believe we have obtained the most accurate information available for the types of derivative contracts we hold.

The fair values of our derivative instruments are sensitive to changes in forward pricing on natural gas, NGLs and crude oil. The financial position of these derivatives at September 30, ~~2017,~~2020, a net liability position of ~~$63.4~~$15.6 million, reflects the present value, adjusted for counterparty credit risk, of the amount we expect to receive or pay in the future on our derivative contracts. If forward pricing on natural gas, NGLs and crude oil were to increase by 10%, the result would be a fair value reflecting a net liability of ~~$149.9 million, ignoring an adjustment for counterparty credit risk.~~$(136.8) million. If forward pricing on natural gas, NGLs and crude oil were to decrease by 10%, the result would be a fair value reflecting a net asset of ~~$22.2 million, ignoring an adjustment for counterparty credit risk.~~$106.1 million.

Due to their cash or near-cash nature, the carrying value of other financial instruments included in working capital (i.e., cash and cash equivalents, accounts receivable, accounts payable) approximates their fair value. Long-term debt is primarily the other financial instrument for which carrying value could vary significantly from fair value. We determined the supplemental fair value disclosures for our long-term debt as follows:

Contingent consideration liabilities related to business acquisitions are carried at fair ~~value.~~value until the end of the related earn-out period.

We categorize the inputs to the fair value measurements of financial assets and liabilities at each balance sheet reporting date using a three-tier fair value hierarchy that prioritizes the significant inputs used in measuring fair value:

The following table shows a breakdown by fair value hierarchy category for (1) financial instruments measurements included on our Consolidated Balance Sheets at fair value and (2) supplemental fair value disclosures for other financial instruments:

			September 30, 2017															September 30, 2020
						Fair Value															Fair Value
			Carrying Value			Total			Level 1			Level 2			Level 3			Carrying Value			Total			Level 1			Level 2			Level 3
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value:	Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value:
Assets from commodity derivative contracts (1)	Assets from commodity derivative contracts (1)		$	32.0		$	32.0		$	—		$	29.0		$	3.0		$	168.4		$	168.4		$	—		$	168.4		$	—
Liabilities from commodity derivative contracts (1)	Liabilities from commodity derivative contracts (1)			95.4			95.4			—			86.5			8.9			184.0			184.0			—			183.7			0.3
Permian Acquisition contingent consideration (2)				290.8			290.8			—			—			290.8
TPL contingent consideration (3)				2.5			2.5			—			—			2.5
TPL contingent consideration (2)																			2.3			2.3			—			—			2.3
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value:	Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value:
Cash and cash equivalents	Cash and cash equivalents			103.9			103.9			—			—			—			248.0			248.0			—			—			—
TRP Revolver	TRP Revolver			430.0			430.0			—			430.0			—			100.0			100.0			—			100.0			—
Senior unsecured notes	Senior unsecured notes			3,778.5			3,881.2			—			3,881.2			—			7,145.0			7,206.0			—			7,206.0			—
Accounts receivable securitization facility				278.1			278.1			—			278.1			—
Securitization Facility																			250.0			250.0			—			250.0			—

		December 31, 2016															December 31, 2019
					Fair Value															Fair Value
			Carrying Value		Total			Level 1			Level 2			Level 3				Carrying Value		Total			Level 1			Level 2			Level 3
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value:	Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value:
Assets from commodity derivative contracts (1)	Assets from commodity derivative contracts (1)		$	21.0		$	21.0		$	—		$	19.6		$	1.4		$	136.5		$	136.5		$	—		$	136.2		$	0.3
Liabilities from commodity derivative contracts (1)	Liabilities from commodity derivative contracts (1)			74.2			74.2			—			69.3			4.9			142.6			142.6			—			142.0			0.6
Permian Acquisition contingent consideration (2)				—			—			—			—			—
TPL contingent consideration (3)				2.6			2.6			—			—			2.6
TPL contingent consideration (2)																			2.3			2.3			—			—			2.3
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value:	Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value:
Cash and cash equivalents	Cash and cash equivalents			68.0			68.0			—			—			—			291.1			291.1			—			—			—
TRP Revolver	TRP Revolver			150.0			150.0			—			150.0			—			—			—			—			—			—
Senior unsecured notes	Senior unsecured notes			4,057.3			4,101.6			—			4,101.6			—			7,028.5			7,376.9			—			7,376.9			—
Accounts receivable securitization facility				275.0			275.0			—			275.0			—
Securitization Facility																			370.0			370.0			—			370.0			—

Additional Information Regarding Level 3 Fair Value Measurements Included on Our Consolidated Balance Sheets

We reported certain of our swaps and option contracts at fair value using Level 3 inputs due to such derivatives not having observable market prices or implied volatilities ~~or market prices~~ for substantially the full term of the derivative asset or liability. For valuations that include both observable and unobservable inputs, if the unobservable input is determined to be significant to the overall inputs, the entire valuation is categorized in Level 3. This includes derivatives valued using indicative price quotations whose contract length extends into unobservable periods.

The fair value of these swaps is determined using a discounted cash flow valuation technique based on a forward commodity basis curve. For these derivatives, the primary input to the valuation model is the forward commodity basis curve, which is based on observable or public data sources and extrapolated when observable prices are not available.

~~As of September 30, 2017, we had 31 commodity swap and option contracts categorized as Level 3.~~ The significant unobservable inputs used in the fair value measurements of our Level 3 derivatives ~~are~~were (i) the forward natural gas liquids pricing curves, for which a significant portion of the derivative’s term is beyond available forward pricing and (ii) implied volatilities, which are unobservable as a result of inactive natural gas liquids options trading. The change in the fair value of Level 3 derivatives associated with a 10% change in the forward basis curve where prices are not observable iswas immaterial. As of September 30, 2020, we had 3 commodity swap and option contracts categorized as Level 3.

The fair value of the Permian Acquisition contingent consideration was determined using a Monte Carlo simulation model. Significant inputs used in the fair value measurement include expected gross margin (calculated in accordance with the terms of the purchase and sale agreements), term of the earn-out period, risk adjusted discount rate and volatility associated with the underlying assets. A significant decrease in expected gross margin during the earn-out period, or significant increase in the discount rate or volatility would result in a lower fair value estimate. The fair value of the TPL contingent consideration was determined using a probability-based model measuring the likelihood of meeting certain volumetric measures. The inputs ~~for both models~~ are not observable; therefore, the entire ~~valuations~~valuation of the contingent ~~considerations are~~consideration is categorized in Level 3. ~~Changes in the fair value of these liabilities are included in Other income (expense) in the Consolidated Statements of Operations.~~

The following table summarizes the changes in fair value of our financial instruments classified as Level 3 in the fair value hierarchy:

Nonfinancial assets and liabilities, such as long-lived assets, are measured at fair value on a nonrecurring basis upon impairment. In the first quarter of 2020, we recorded non-cash pre-tax impairments of $2,442.8 million. The impairment charge is primarily associated with the partial impairment of gas processing facilities and gathering systems associated with our Mid-Continent operations and full impairment of our Coastal operations. For disclosures related to valuation techniques, see Note 4 – Property, Plant and Equipment and Intangible Assets.

The techniques described above may produce a fair value calculation that may not be indicative or reflective of future fair values. Furthermore, while we believe our valuation techniques are appropriate and consistent with other market participants, the use of different techniques or assumptions to determine fair value of certain financial and nonfinancial assets and liabilities could result in a different fair value measurement at the reporting date.

We do not have any employees. Targa provides operational, general and administrative and other services to us associated with our existing assets and assets acquired from third parties. Targa performs centralized corporate functions for us, such as legal, accounting, treasury, insurance, risk management, health, safety and environmental, information technology, human resources, credit, payroll, internal audit, taxes, engineering and marketing.

Our Partnership Agreement governs the reimbursement of costs incurred by Targa on behalf of us. Targa charges us for all the direct costs of the employees assigned to our operations, as well as all general and administrative support costs other than ~~(1)~~ costs attributable to Targa’s status as a separate reporting ~~company and (2) costs of Targa providing management and support services to certain unaffiliated spun-off entities.~~company. We generally reimburse Targa monthly for cost allocations to the extent that Targa has made a cash outlay.

The following table summarizes transactions with ~~Targa. Management believes these transactions are executed on terms that are fair and reasonable.~~Targa:

	Three Months Ended September 30,				Nine Months Ended September 30,				Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016		2020		2019		2020		2019
Targa billings of payroll and related costs included in operating expense	$	54.0	$	42.6	$	148.6	$	125.0
Targa billings of payroll and related costs included in operating expenses									$	59.5	$	61.6	$	191.7	$	177.3
Targa allocation of general and administrative expense		43.2		40.1		126.6		117.7		51.3		59.5		159.8		188.4
Cash distributions to Targa based on IDR, general partner and limited partner ownership (1)		222.6		178.9		624.7		395.1
Cash distributions to Targa based on general partner and limited partner ownership										48.8		239.6		338.3		913.1
Cash contributions from Targa related to limited partner ownership ~~(2)~~(1)		14.7		210.7		1,587.5		1,167.2		—		9.8		49.0		196.0
Cash contributions from Targa to maintain its 2% general partner ownership		0.3		4.3		32.5		23.8		—		0.2		1.0		4.0

We are a party to various legal, administrative and regulatory proceedings that have arisen in the ordinary course of our business. We are also a party to various proceedings with governmental environmental agencies, including but not limited to the U.S. Environmental Protection Agency, Texas Commission on Environmental Quality, Oklahoma Department of Environmental Quality, New Mexico Environment Department, Louisiana Department of Environmental Quality and North Dakota Department of Environmental Quality, which assert monetary sanctions for alleged violations of environmental regulations, including air emissions, discharges into the environment and reporting deficiencies, related to events that have arisen at certain of our facilities in the ordinary course of our business. See Part II—Item 1. Legal Proceedings for further details.

The following table presents the estimated minimum revenue related to unsatisfied performance obligations at the end of the reporting period, and is comprised of fixed consideration primarily attributable to contracts with minimum volume commitments, for which a guaranteed amount of revenue can be calculated. These contracts are comprised primarily of gathering and processing, fractionation, export, terminaling and storage agreements, with remaining contract terms ranging from 1 to 19 years.

Based on the optional exemptions we elected to apply, the amounts presented in the table above exclude remaining performance obligations for (i) variable consideration for which the allocation exception is met and (ii) contracts with an original expected duration of one year or less.

For disclosures related to disaggregated revenue, see Note 15– Segment Information.

We operate in ~~two~~2 primary segments: (i) Gathering and Processing, and (ii) Logistics and ~~Marketing~~Transportation (also referred to as the Downstream Business). Our reportable segments include operating segments that have been aggregated based on the nature of the products and services provided.

Our Gathering and Processing segment includes assets used in the gathering of natural gas produced from oil and gas wells and processing this raw natural gas into merchantable natural gas by extracting NGLs and removing impurities; and assets used for crude oil purchase and sale, gathering and terminaling. The Gathering and Processing segment's assets are located in the Permian Basin of West Texas and Southeast New ~~Mexico;~~Mexico (including the Midland, Central and Delaware Basins); the Eagle Ford Shale in South Texas; the Barnett Shale in North Texas; the Anadarko, Ardmore, and Arkoma Basins in Oklahoma (including the SCOOP and STACK) and South Central Kansas; the Williston Basin in North Dakota (including the Bakken and inThree Forks plays); and the onshore and near offshore regions of the Louisiana Gulf Coast and the Gulf of Mexico.

Our Logistics and ~~Marketing~~Transportation segment includes ~~all~~ the activities and assets necessary to convert mixed NGLs into NGL products and ~~provides certain value added~~also includes other assets and value-added services such as transporting, storing, fractionating, terminaling ~~distributing~~ and marketing of NGLs ~~the storage~~ and ~~terminaling of refined petroleum~~NGL products, ~~and crude oil~~including services to LPG exporters; and certain natural gas supply and marketing activities in support of our other ~~businesses including services to LPG exporters. It~~businesses. The Logistics and Transportation segment also includes ~~certain natural gas supply and marketing activities in support of our other operations,~~the Grand Prix NGL pipeline (“Grand Prix”), as well as ~~transporting~~our equity interest in Gulf Coast Express Pipeline LLC (“GCX”), a natural gas ~~and NGLs. The Logistics and Marketing segment also includes our~~pipeline transporting volumes from West Texas to the Gulf Coast. Grand Prix ~~project.~~

~~Logistics~~connects our gathering and ~~Marketing operations~~processing positions in the Permian Basin, Southern Oklahoma and North Texas with our downstream facilities in Mont Belvieu, Texas. The associated assets are generally connected to and supplied in part by our Gathering and Processing segment and, except for pipelines and smaller terminals, are located predominantly ~~located~~ in Mont Belvieu and Galena Park, Texas, and ~~Channelview, Texas;~~in Lake Charles, ~~Louisiana and Tacoma, Washington.~~Louisiana.

Other contains the ~~results (including any hedge ineffectiveness) of commodity derivative activities included in operating margin. and~~ mark-to-market gains/losses related to derivative contracts that were not designated as cash flow hedges. Elimination of inter-segment transactions are reflected in the corporate and eliminations column.

	Three Months Ended September 30, 2017												Three Months Ended September 30, 2020
	Gathering and Processing		Logistics and Marketing		Other			Corporate and Eliminations			Total		Gathering and Processing		Logistics and Transportation		Other		Corporate and Eliminations			Total
Revenues
Sales of commodities	$	200.3	$	1,672.2	$	(1.0	)	$	—		$	1,871.5	$	135.7	$	1,616.5	$	88.6	$	—		$	1,840.8
Fees from midstream services		148.5		111.8		—			—			260.3		126.2		148.1		—		—			274.3
		348.8		1,784.0		(1.0	)		—			2,131.8		261.9		1,764.6		88.6		—			2,115.1
Intersegment revenues
Sales of commodities		783.7		80.6		—			(864.3	)		—		611.9		37.4		—		(649.3	)		—
Fees from midstream services		1.7		7.0		—			(8.7	)		—		1.7		8.5		—		(10.2	)		—
		785.4		87.6		—			(873.0	)		—		613.6		45.9		—		(659.5	)		—
Revenues	$	1,134.2	$	1,871.6	$	(1.0	)	$	(873.0	)	$	2,131.8	$	875.5	$	1,810.5	$	88.6	$	(659.5	)	$	2,115.1
Operating margin	$	198.3	$	115.9	$	(1.0	)	$	—		*		$	261.0	$	280.4	$	88.6	$	—		$	630.0
Other financial information:
Total assets (1)	$	10,644.3	$	3,240.9	$	30.8		$	56.2		$	13,972.2	$	8,929.4	$	6,841.2	$	78.2	$	145.8		$	15,994.6
Goodwill	$	256.6	$	—	$	—		$	—		$	256.6	$	45.2	$	—	$	—	$	—		$	45.2
Capital expenditures	$	295.9	$	71.0	$	—		$	11.8		$	378.7	$	63.6	$	69.0	$	—	$	4.0		$	136.6

	Three Months Ended September 30, 2016											Three Months Ended September 30, 2019
	Gathering and Processing		Logistics and Marketing		Other		Corporate and Eliminations			Total		Gathering and Processing		Logistics and Transportation		Other			Corporate and Eliminations			Total
Revenues
Sales of commodities	$	172.2	$	1,215.3	$	11.2	$	—		$	1,398.7	$	292.3	$	1,403.1	$	(101.2	)	$	—		$	1,594.2
Fees from midstream services		120.6		133.0		—		—			253.6		173.0		135.3		—			—			308.3
		292.8		1,348.3		11.2		—			1,652.3		465.3		1,538.4		(101.2	)		—			1,902.5
Intersegment revenues
Sales of commodities		574.8		76.3		—		(651.1	)		—		534.0		34.9		—			(568.9	)		—
Fees from midstream services		1.9		6.6		—		(8.5	)		—		1.9		7.4		—			(9.3	)		—
		576.7		82.9		—		(659.6	)		—		535.9		42.3		—			(578.2	)		—
Revenues	$	869.5	$	1,431.2	$	11.2	$	(659.6	)	$	1,652.3	$	1,001.2	$	1,580.7	$	(101.2	)	$	(578.2	)	$	1,902.5
Operating margin	$	149.4	$	126.0	$	11.2	$	—			*	$	246.5	$	228.9	$	(101.2	)	$	—		$	374.2
Other financial information:
Total assets (1)	$	10,047.3	$	2,737.5	$	47.2	$	76.2		$	12,908.2	$	12,326.5	$	6,475.0	$	2.9		$	53.9		$	18,858.3
Goodwill	$	393.0	$	—	$	—	$	—		$	393.0	$	46.6	$	—	$	—		$	—		$	46.6
Capital expenditures	$	97.1	$	36.2	$	—	$	1.3		$	134.6	$	230.3	$	301.2	$	—		$	10.8		$	542.3

* Total operating margin is not presented in this table as it represents a non-GAAP measure.

	Nine Months Ended September 30, 2016											Nine Months Ended September 30, 2019
	Gathering and Processing		Logistics and Marketing		Other		Corporate and Eliminations			Total		Gathering and Processing		Logistics and Transportation		Other			Corporate and Eliminations			Total
Revenues
Sales of commodities	$	441.3	$	3,384.7	$	56.9	$	—		$	3,882.9	$	847.4	$	4,508.5	$	(101.1	)	$	—		$	5,254.8
Fees from midstream services		360.9		434.6		—		—			795.5		549.1		393.3		—			—			942.4
		802.2		3,819.3		56.9		—			4,678.4		1,396.5		4,901.8		(101.1	)		—			6,197.2
Intersegment revenues
Sales of commodities		1,455.8		176.3		—		(1,632.1	)		—		1,896.5		117.0		—			(2,013.5	)		—
Fees from midstream services		5.8		15.1		—		(20.9	)		—		5.3		20.1		—			(25.4	)		—
		1,461.6		191.4		—		(1,653.0	)		—		1,901.8		137.1		—			(2,038.9	)		—
Revenues	$	2,263.8	$	4,010.7	$	56.9	$	(1,653.0	)	$	4,678.4	$	3,298.3	$	5,038.9	$	(101.1	)	$	(2,038.9	)	$	6,197.2
Operating margin	$	404.1	$	424.6	$	56.9	$	—			*	$	716.8	$	565.0	$	(101.1	)	$	—		$	1,180.7
Other financial information:
Total assets (1)	$	10,047.3	$	2,737.5	$	47.2	$	76.2		$	12,908.2	$	12,326.5	$	6,475.0	$	2.9		$	53.9		$	18,858.3
Goodwill	$	393.0	$	—	$	—	$	—		$	393.0	$	46.6	$	—	$	—		$	—		$	46.6
Capital expenditures	$	271.3	$	151.9	$	—	$	3.3		$	426.5	$	1,068.7	$	1,197.5	$	—		$	38.7		$	2,304.9

* Total operating margin is not presented in this table as it represents a non-GAAP measure.

The following table shows our consolidated revenues disaggregated by product and service for the periods presented:

	Three Months Ended September 30,					Nine Months Ended September 30,				Three Months Ended September 30,					Nine Months Ended September 30,
	2017			2016		2017		2016		2020		2019			2020		2019
Sales of commodities:
Revenue recognized from contracts with customers:
Natural gas	$	504.1		$	465.6	$	1,480.9	$	1,102.0	$	351.1	$	305.3		$	893.9	$	934.2
NGL		1,274.9			866.7		3,623.9		2,575.8		1,312.9		1,160.5			3,382.0		3,752.4
Condensate		44.9			35.0		135.9		96.2
Condensate and crude oil											54.4		178.7			217.8		488.4
Petroleum products		48.6			20.2		108.5		52.0		13.2		11.5			69.8		87.5
Derivative activities		(1.0	)		11.2		3.9		56.9
											1,731.6		1,656.0			4,563.5		5,262.5
Non-customer revenue:
Derivative activities - Hedge											19.2		41.5			139.4		106.1
Derivative activities - Non-hedge (1)											90.0		(103.3	)		197.9		(113.8	)
											109.2		(61.8	)		337.3		(7.7	)
Total sales of commodities											1,840.8		1,594.2			4,900.8		5,254.8
		1,871.5			1,398.7		5,353.1		3,882.9
Fees from midstream services:
Fractionating and treating		29.8			33.2		92.8		94.8
Storage, terminaling, transportation and export		75.0			89.7		247.8		316.3
Revenue recognized from contracts with customers:
Gathering and processing		138.0			110.9		368.5		329.9		123.7		171.6			347.1		543.7
NGL transportation, fractionation and services											43.8		45.8			116.7		122.0
Storage, terminaling and export											96.6		84.6			285.5		254.7
Other		17.5			19.8		49.9		54.5		10.2		6.3			37.4		22.0
Total fees from midstream services											274.3		308.3			786.7		942.4
		260.3			253.6		759.0		795.5
Total revenues	$	2,131.8		$	1,652.3	$	6,112.1	$	4,678.4	$	2,115.1	$	1,902.5		$	5,687.5	$	6,197.2

The following table shows a reconciliation of reportable segment operating margin to income (loss) before income taxes for the periods presented:

	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016			2020			2019			2020			2019
Reconciliation of reportable segment operating margin to income (loss) before income taxes:
Gathering and Processing operating margin	$	198.3		$	149.4		$	549.3		$	404.1		$	261.0		$	246.5		$	753.7		$	716.8
Logistics and Marketing operating margin		115.9			126.0			358.5			424.6
Logistics and Transportation operating margin														280.4			228.9			806.0			565.0
Other operating margin		(1.0	)		11.2			3.9			56.9			88.6			(101.2	)		215.9			(101.1	)
Depreciation and amortization expenses		(208.3	)		(184.0	)		(602.8	)		(563.6	)
General and administrative expenses		(46.6	)		(44.0	)		(139.4	)		(132.3	)
Impairment of property, plant and equipment		(378.0	)		—			(378.0	)		—
Impairment of goodwill		—			—			—			(24.0	)
Depreciation and amortization expense														(203.7	)		(244.3	)		(647.3	)		(718.9	)
General and administrative expense														(56.3	)		(65.6	)		(171.7	)		(212.3	)
Impairment of long-lived assets														—			—			(2,442.8	)		—
Interest expense, net		(51.9	)		(57.9	)		(169.5	)		(171.2	)		(94.9	)		(84.2	)		(283.0	)		(229.2	)
Equity earnings (loss)														18.6			10.0			54.1			15.9
Gain (loss) on sale or disposition of business and assets														(58.0	)		(0.5	)		(58.0	)		(3.6	)
Write-down of assets														(13.5	)		(17.9	)		(13.5	)		(17.9	)
Gain (loss) from financing activities														(13.7	)		—			47.4			(1.4	)
Gain (loss) from sale of equity-method investment														—			65.8			—			65.8
Change in contingent considerations														—			—			—			(8.8	)
Other, net		126.6			(5.8	)		78.4			5.0			0.6			—			(0.3	)		(0.1	)
Income (loss) before income taxes	$	(245.0	)	$	(5.1	)	$	(299.6	)	$	(0.5	)	$	209.1		$	37.5		$	(1,739.5	)	$	70.2

Item 2. Management’s Discussion and Analysis ofof Financial Condition and Results of Operations.

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations contained in our Annual Report on Form 10-K for the year ended December 31, ~~2016~~2019 (“Annual Report”), as well as the unaudited consolidated financial statements and ~~Notes~~notes hereto included in this Quarterly Report on Form 10-Q.

Targa Resources Partners LP (“we,” “our,” the “Partnership” or “TRP”) is a Delaware limited partnership formed in October 2006 by Targa Resources Corp. (“TRC” or “Targa”). Our common units were listed on the NYSE under the symbol “NGLS” prior to TRC’s acquisition on February 17, 2016 of all our outstanding common units that it and its subsidiaries did not already own. Our 9.00% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (the “Preferred Units”) remain outstanding as preferred limited partner interests in us and continue to trade on the NYSE under the symbol ~~“NGLS PRA.~~“NGLS/PA.”

Targa Resources GP LLC, our general partner, is a Delaware limited liability company formed by Targa in October 2006 to own a 2% general partner interest in us. Its primary business purpose is to manage our affairs and operations. Targa Resources GP LLC is an indirect wholly owned subsidiary of Targa.

On February 17, 2016, TRC completed the previously announced transactions contemplated by the Merger Agreement, by and among us, our general partner, TRC and Merger Sub pursuant to which TRC acquired indirectly all of our outstanding common units that TRC and its subsidiaries did not already own. Upon the terms and conditions set forth in the Merger Agreement, Merger Sub merged with and into TRP, with TRP continuing as the surviving entity and as a subsidiary of TRC. Following the closing of the TRC/TRP Merger on February 17, 2016, TRC owns all our outstanding common units.

To provide these services, we operate in two primary segments: (i) Gathering and Processing, and (ii) Logistics and ~~Marketing~~Transportation (also referred to as the Downstream Business).

Our Gathering and Processing segment includes assets used in the gathering and purchase and sale of natural gas produced from oil and gas wells and processing this raw natural gas into merchantable natural gas by extracting NGLs and removing impurities; and assets used for crude oil purchase and sale, gathering and terminaling. The Gathering and Processing segment's assets are located in the Permian Basin of West Texas and Southeast New ~~Mexico;~~Mexico (including the Midland, Central and Delaware Basins); the Eagle Ford Shale in South Texas; the Barnett Shale in North Texas; the Anadarko, Ardmore, and Arkoma Basins in Oklahoma (including the SCOOP and STACK) and South Central Kansas; the Williston Basin in North Dakota (including the Bakken and inThree Forks plays); and the onshore and near offshore regions of the Louisiana Gulf Coast and the Gulf of Mexico.

~~Logistics~~NGL pipeline (“Grand Prix”), as well as our equity interest in Gulf Coast Express Pipeline LLC (“GCX”), a natural gas pipeline transporting volumes from West Texas to the Gulf Coast. Grand Prix connects our gathering and ~~Marketing operations~~processing positions in the Permian Basin, Southern Oklahoma and North Texas with our downstream facilities in Mont Belvieu, Texas. The associated assets, including these pipelines, are generally connected to and supplied in part by our Gathering and Processing segment and, except for the pipelines and smaller terminals, are located predominantly ~~located~~ in Mont Belvieu and Galena Park, Texas, and ~~Channelview, Texas;~~in Lake Charles, ~~Louisiana and Tacoma, Washington.~~Louisiana.

Other contains the ~~results (including any hedge ineffectiveness) of our commodity~~unrealized mark-to-market gains/losses related to derivative ~~activities~~contracts that ~~are included in operating margin.~~were not designated as cash flow hedges.

During the nine months ended September 30, 2020, global commodity prices declined due to factors that significantly impacted both supply and demand. As the COVID-19 pandemic spread and travel and other restrictions were implemented globally, the demand for commodities declined substantially. Additionally, certain major oil producing nations significantly increased their oil and gas production late in the first quarter which further contributed to the surplus production of commodities. Despite these nations subsequently agreeing to reduce global commodity supplies and global economies beginning to re-open, commodity prices remain weak relative to historical levels and continue to remain volatile. Reduced economic activity due to the COVID-19 pandemic, combined with uncertainty around global commodity supply and demand, has contributed to depressed crude oil, condensate, NGL and natural gas prices. Furthermore, the decline in commodity prices led many exploration and production companies to reduce planned capital expenditures for drilling and production activities and also led to some companies shutting in wells in the first half of 2020. Such price and activity declines negatively impacted our operations by (i) reducing investments by third parties in the development of new oil and gas reserves, therefore reducing volumes coming onto our systems in the future, (ii) decreasing volumes processed in our facilities and transported on our pipelines and (iii) reducing the prices we receive from the sale of commodities. While commodity prices remain low relative to historical levels and uncertainties associated with the impacts of COVID-19 continue, production from wells that were previously shut-in during the first half of 2020 across our operating areas has largely resumed. Though energy demand has begun to recover compared to the first half of 2020, the pace and scope of recovery is uncertain at this time and may extend beyond 2020.

These circumstances have caused significant market volatility and business disruption. In our Gathering and Processing areas of operation, producers have reduced their drilling activity to varying degrees, which may lead to lower volume growth in the near term and reduced demand for our services. Producer activity also generates demand in our Downstream Business for transportation, fractionation, storage and other fee-based services, which may decrease in the near term.

There has been, and we believe will continue to be, significant volatility in commodity prices and in the relationships among NGL, crude oil and natural gas prices. Due to the recent volatility in commodity prices, we are uncertain of what pricing and market demand will be throughout 2020, and, as a result, demand for our services may decrease. Across our operations, particularly in our Downstream Business, we benefit from long-term fee-based arrangements for our services, regardless of the actual volumes processed or delivered. The significant level of margin we derive from fee-based arrangements, combined with our hedging arrangements, helps to mitigate our exposure to commodity price movements. For additional information regarding our hedging activities, see “Item 3. Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk.”

Due to the significant decline in commodity prices and the increased volatility in the broader market, the ability of companies in the oil and gas industry to seek financing and access the capital markets on favorable terms or at all has been negatively impacted. In these conditions, investors may be more likely to limit the amounts of their investments as well as seek more restrictive terms and higher costs on any financing. While these effects have increased the costs of debt and equity financing for the Company and others in our industry, we believe we have sufficient access to financial resources and liquidity necessary to meet our requirements for working capital, debt service payments and capital expenditures through the remainder of 2020 and beyond.

In a response to current market conditions, in the first quarter of 2020, we announced that our Board of Directors approved a reduction in the Company’s quarterly common dividend to $0.10 per share for the quarter ended March 31, 2020 from $0.91 per share in the previous quarter. This reduction provided for approximately $755 million of additional annual direct cash flow, resulting in significant free cash flow available to reduce debt. We also reduced our estimated 2020 net growth capital expenditures to about $700 million from our previously disclosed ranges of $700 million to $800 million in the first quarter of 2020 and $1.2 billion to $1.3 billion in the fourth quarter of 2019. The vast majority of spending is for major ongoing growth capital projects where the capital is already predominantly spent. We continue to work through numerous internal initiatives to respond to current market conditions, including identifying and implementing cost reduction measures such as reducing or deferring non-essential operating and general and administrative expenses.

We believe that our long-term strategy, combined with our high-quality asset portfolio, allows us to generate attractive cash flows even in a low commodity price environment. Geographic, business and customer diversity enhances our ability to generate sufficient cash flows to fund our requirements. Our assets are positioned in strategic oil and gas producing areas across multiple basins and provide services under attractive contract terms to a diverse mix of customers across our operational areas. Our contract portfolio has attractive rates and term characteristics, including a significant fee-based component, especially in our Downstream Business. Our Gathering and Processing segment contract mix also has components of fee-based margin, such as fee floors and other fee-based services which mitigate against low commodity prices.

We are currently experiencing no material issues with potential workforce disruptions, and we remain focused on safeguarding employee health and safety and ensuring safe and reliable operations in response to COVID-19. Additionally, we are currently experiencing no material supply chain disruptions as a result of the COVID-19 pandemic, and our relationships with our major customers continues to be strong. However, if any of these circumstances change, our business could be adversely affected. Further, as there is significant uncertainty around the breadth and duration of the disruptions to global markets related to the aforementioned current events, we are unable to determine the extent that these events could materially impact our future financial position, operations and/or cash flows.

On March 1, 2017, we completed the purchase of 100% of the membership interests of Outrigger Delaware Operating, LLC, Outrigger Southern Delaware Operating, LLC (together “New Delaware”) and Outrigger Midland ~~Operating, LLC (“New Midland” and together with New Delaware, the “Permian Acquisition”).~~

We paid $484.1 million in cash at closing on March 1, 2017, and paid an additional $90.0 million in cash on May 30, 2017 (collectively, the "initial purchase price"). Contributions from TRC were used to fund the cash portion of the Permian Acquisition purchase price. Subject to certain performance-linked measures and other conditions, additional cash of up to $935.0 million may be payable to the sellers of New Delaware and New Midland in potential earn-out payments that would occur in 2018 and 2019. The potential earn-out payments will be based upon a multiple of realized gross margin from contracts that existed on March 1, 2017.

New Delaware's gas gathering and processing and crude gathering assets are located in Loving, Winkler, Pecos and Ward counties. The operations are backed by producer dedications of more than 145,000 acres under long-term, largely fee-based contracts, with an average weighted contract life of 14 years. The New Delaware assets include 70 MMcf/d of processing capacity and we are in the process of installing a 60 MMcf/d plant, known as the Oahu Plant, in the Delaware Basin with expectations of commencing operations in the fourth quarter of 2017. Currently, there is 40 MBbl/d of crude gathering capacity on the New Delaware system.

New Midland's gas gathering and processing and crude gathering assets are located in Howard, Martin and Borden counties. The operations are backed by producer dedications of more than 105,000 acres under long-term, largely fee-based contracts, with an average weighted contract life of 13 years. The New Midland assets include 10 MMcf/d of processing capacity. Currently, there is 40 MBbl/d of crude gathering capacity on the New Midland system.

New Delaware's gas gathering and processing assets were connected to our Sand Hills system in the first quarter of 2017, and the New Midland's gas gathering and processing assets were connected to our existing WestTX system in October 2017. We believe connecting the acquired assets to our legacy Permian footprint creates operational and capital synergies, and will afford enhanced flexibility in serving our producer customers.

In November ~~2016,~~2020, we announced ~~plans to restart~~ the ~~idled 45 MMcf/d Benedum~~transfer of an existing cryogenic natural gas processing plant ~~and~~from our North Texas system to ~~add 20 MMcf/d of capacity at~~ our ~~Midkiff Plant in our WestTX~~Permian Midland system. The ~~Benedum~~former Longhorn Plant ~~was idled in September 2014 after the start-up of the 200 MMcf/d Edward Plant,~~will be relocated to, and was brought back online in the first quarter of 2017. The addition of 20 MMcf/d of capacity at our Midkiff Plant was completed in the second quarter of 2017 and increased overall plant capacity of the Midkiff/Consolidator Plant complexinstalled in Reagan County, Texas, ~~from 210 MMcf/d to 230 MMcf/d. Also~~ in November 2016, we announced plans to build the 200 MMcf/d Joyce Plant, which is expected to be completed in the first quarter of 2018. We expect total net growth capital expenditures for the Joyce Plant to be approximately $80 million.

~~In May 2017, we announced plans to build a new plant and expand the gathering footprint of our Permian Midland system in the Midland Basin. This project includes~~2021 as a new 200 MMcf/d cryogenic natural gas processing plant ~~known as~~(the “Heim Plant”). The Heim Plant will process natural gas production from the ~~Johnson Plant, which~~Permian Basin and is expected to begin operations in the ~~third~~fourth quarter of ~~2018. We expect total net growth capital expenditures for the Johnson Plant to be approximately $100 million.~~2021.

~~Also in May 2017,~~In August 2019, we announced ~~plans to build a new plant and expand the gathering footprint~~that we began construction of ~~our Permian Delaware system in the Delaware Basin. This project includes~~ a new 250 MMcf/d cryogenic natural gas processing plant ~~known as~~in the ~~Wildcat~~Midland Basin, the Gateway Plant, which ~~is expected~~commenced operations in the third quarter of 2020.

In March 2018, we announced that we entered into long-term fee-based agreements with an investment grade energy company for natural gas gathering and processing services in the Delaware Basin and for downstream transportation, fractionation and other related services. The agreements are underpinned by the customer's dedication of significant acreage within a large, well-defined area in the Delaware Basin. In addition to ~~begin~~ high-pressure rich gas gathering pipelines and a natural gas processing plant, the Falcon Plant, which were placed into service in 2019, we commenced operations of a second 250 MMcf/d cryogenic natural gas processing plant, the Peregrine Plant, in the second quarter of ~~2018. We expect total net growth capital expenditures for the Wildcat Plant to be approximately $130 million.~~2020.

~~Eagle Ford Shale Natural Gas Gathering~~We provide NGL transportation services on Grand Prix and ~~Processing Joint Ventures~~

In October 2015, we announced that we had entered into the Carnero Joint Ventures with Sanchez Energy Corporation (“Sanchez”) to construct the 200 MMcf/d Raptor Plant and approximately 45 miles of associated pipelines. In July 2016, Sanchez sold its interest in the gathering joint venture to Sanchez Midstream Partners, L.P. (“SNMP”), formerly known as

~~Sanchez Production Partners, L.P., and in November 2016, sold its interest in the processing joint venture to SNMP. Through the Carnero Joint Ventures, we indirectly own~~fractionation services at our Mont Belvieu complex for a 50% interest in the plant and the approximately 45 miles of high pressure gathering pipelines that will connect SNMP's Catarina gathering system to the plant. We hold the capacity on the high pressure gathering pipelines, and pay the gathering joint venture fees for transportation.

~~The Raptor Plant began operations in the second quarter of 2017, and is capable of processing 200 MMcf/d. In February 2017, we announced the addition of compression to increase the processing capacity~~majority of the ~~Raptor Plant to 260 MMcf/d, which we expect to be completed in~~NGLs from the ~~fourth quarter of 2017. The Raptor Plant accommodates growing production from Sanchez’s premier Eagle Ford Shale acreage position in Dimmit, La Salle~~Falcon and ~~Webb Counties, Texas~~Peregrine Plants.

Logistics and from other third party producers. The plant and high pressure gathering pipelines are supported by long-term, firm, fee-based contracts and acreage dedications with Sanchez. We manage operations of the high pressure gathering lines and the plant. Prior to the plant being placed in service, we benefited from Sanchez natural gas volumes that were processed at our Silver Oak facilities in Bee County, Texas.

In May 2017, we acquired a 150 MMcf/d natural gas processing plant (the “Flag City Plant”) and associated assets from subsidiaries of Boardwalk Pipeline Partners, L.P. (“Boardwalk”) for $60.0 million, subject to customary closing adjustments. The gas processing activities under the Flag City Plant contracts have been transferred to our Silver Oak facilities. We shut down the Flag City Plant and are moving the plant and its component parts to other Targa locations.

~~During 2017, we expect to invest approximately $150 million to~~ expand our crude gathering and natural gas processing business in the Williston Basin, North Dakota. The expansion includes the addition of pipelines, LACT units, compression and other infrastructure to support continued growth in producer activity.

Through our 76.8% ownership interest in Venice Energy Services Company, L.L.C. (“VESCO”), we have operated the Venice Gas Plant and the Venice gathering system. On April 4, 2017, VESCO entered into a purchase and sale agreement with Rosefield Pipeline Company, LLC, an affiliate of Arena Energy, LP, to sell its 100% ownership interests in Venice Gathering System, L.L.C. (“VGS”), a Delaware limited liability company ~~engaged in the business of transporting natural gas in interstate commerce, under authorization granted by and subject to the jurisdiction of the Federal Energy Regulatory Commission (“FERC”), for approximately $0.4 million in cash.~~ ~~Additionally, the VGS asset retirement obligations were assumed by the buyer.~~ VGS owns and operates a natural gas gathering system in the Gulf of Mexico. Historically, VGS has been reported in our Gas Gathering and Processing segment. After the sale of VGS, we continue to operate the Venice Gas Plant through our ownership in VESCO. Targa Midstream Services LLC operated the Venice gathering system for four months after closing pursuant to a Transition Services Agreement with VGS.

In ~~May 2017,~~February 2019, we announced an extension to our Grand Prix NGL pipeline system (the “Central Oklahoma Extension”), which will extend from Southern Oklahoma to the STACK region of Central Oklahoma where it will connect with The Williams Companies, Inc. (“Williams”) Bluestem Pipeline, linking the Conway, Kansas, and Mont Belvieu, Texas, NGL markets. In connection with this project, Williams has committed significant volumes to us that we will transport on Grand Prix and fractionate at our Mont Belvieu facilities. The Central Oklahoma Extension is expected to be operational by the end of the fourth quarter of 2020. Transportation volumes on the Central Oklahoma Extension accrue solely to Targa’s benefit and are not included in Grand Prix Pipeline LLC (“Grand Prix Joint Venture”), a consolidated subsidiary of which Targa owns a 56% interest.

In November 2018, we announced plans to construct atwo new ~~common carrier NGL pipeline. The NGL pipeline~~110 MBbl/d fractionation trains in Mont Belvieu, Texas (“~~Grand Prix”~~Train 7” and “Train 8”). Train 7 commenced operations in the first quarter of 2020 and Train 8 commenced operations in the third quarter of 2020. In January 2019, Williams committed to Targa significant volumes which Targa will transport ~~volumes from the Permian Basin~~on Grand Prix and ~~our North Texas system~~fractionate at Targa’s Mont Belvieu facilities (including Train 7). Williams was also granted an option to ~~our fractionation and storage complex~~purchase a 20% equity interest in the ~~NGL market hub at Mont Belvieu, Texas. Grand Prix will be supported~~fractionation train, which was originally wholly owned by ~~our volumes~~Targa. Williams exercised its initial option and ~~other third party customer commitments, and is expected~~executed a joint venture agreement with us with respect to ~~be in service~~Train 7 in the second quarter of 2019. ~~The capacity of the pipeline from the Permian Basin~~Certain fractionation-related infrastructure for Train 7, such as storage caverns and brine handling, will be ~~approximately 300 MBbl/d, expandable to 550 MBbl/d.~~funded and owned 100% by Targa.

In ~~September 2017,~~February 2019, we ~~sold~~announced plans to ~~funds managed~~further expand our LPG export capabilities of propane and butanes at our Galena Park Marine Terminal by ~~Blackstone Energy Partners ("Blackstone") a 25 percent interest in~~increasing refrigeration capacity and associated load rates. With the additional infrastructure, we increased our consolidated subsidiary, Grand Prix Pipeline LLC (the "Grand Prix Joint Venture"). We are the operator and construction manager of Grand Prix. Our share of total growth capital expenditures for Grand Prix is expectedeffective export capacity up to ~~be approximately $975 million, with approximately $275 million of spending in 2017.~~

~~Concurrent with the sale of the minority interest~~15 MMBbl per month in the ~~Grand Prix Joint Venture to Blackstone, we~~third quarter of 2020, depending upon the mix of propane and ~~EagleClaw Midstream Ventures, LLC ("EagleClaw"), a Blackstone portfolio company, executed a long-term Raw Product Purchase Agreement~~ ~~for transportation~~butane demand, vessel size and ~~fractionation~~ ~~services whereby EagleClaw has dedicated and committed significant NGLs associated with EagleClaw's natural gas volumes produced or processed in the Delaware Basin.~~availability of supply, among other factors.

In October ~~2017, we announced that~~2020, we executed ~~a letter of intent along with Kinder Morgan~~agreements to sell our assets in Channelview, Texas Pipeline LLC, a subsidiary of Kinder Morgan, Inc. (“Kinder Morgan”) and DCP Midstream, LP with respect to the joint development of the proposed Gulf Coast Express Pipeline Project ("GCX Project"), which would provide an outlet for ~~increased natural gas production from the Permian Basin to growing markets along the Texas Gulf Coast. Under the terms of the letter of intent, we would own a 25 percent interest~~approximately $58 million (the “October 2020 Sale”). The sale closed in the ~~GCX Project.~~ ~~KMTP would serve as~~fourth quarter of 2020.

In November 2019, we executed agreements to sell our crude and storage business in Permian Delaware for approximately $134 million. The sale closed in the ~~operator and constructor~~first quarter of the GCX Project, and we would commit significant volumes to it, including certain volumes provided by Pioneer Natural Resources Company (“Pioneer”), a joint owner in our WestTX Permian Basin system~~. The participation of the three parties involved with the GCX Project is subject to negotiation and execution of definitive agreements.~~2020.

The GCX Project is expected to have capacity of approximately 1.92 billion cubic feet per day, and would include a lateral into the Midland Basin, consisting of approximately 50 miles of 36-inch pipeline and associated compression to serve gas processing facilities owned by us, as well as those owned jointly by us and Pioneer in our WestTX system. The expected in-service date of the pipeline continues to be scheduled for the second half of 2019, pending the timely completion of definitive agreements with shippers and a final investment decision by the three parties.

On ~~February 23, 2017, we amended our account receivable securitization facility (“Securitization Facility”) to increase the facility size to $350.0 million from $275.0 million.~~

~~On June 26, 2017,~~November 2, 2020, we redeemed the $559.6 million remaining balance of our 6⅜5¼% Senior Notes due ~~August 2022 (“6⅜~~2023.

In the third quarter of 2020, we issued $1.0 billion of 4⅞% Senior ~~Notes”). The redemption price was 103.188%~~Notes due 2031, resulting in net proceeds of $991.0 million. A portion of the ~~principal amount. The $278.7~~net proceeds from the issuance were used to fund the concurrent cash tender offer (the “Tender Offer”) and redemption payments for our 6¾% Senior Notes due 2024 (the “6¾% Notes”), with the remainder used for repayment of borrowings under the TRP Revolver.

We accepted for purchase all the notes that were validly tendered as of the early tender date, which totaled $262.1 million ~~principal amount outstanding was~~and redeemed ~~on June 26, 2017 for a total redemption payment of $287.6 million, excluding accrued interest.~~

~~On October 17, 2017, we issued $750.0 million~~the remaining aggregate principal amount of 5%the 6¾% Notes, which totaled $318.0 million. We recorded a loss due to debt extinguishment of $13.7 million comprised of $11.1 million premiums paid and a write-off of $2.6 million of debt issuance costs.

Additionally, during the first half of 2020, we repurchased a portion of our outstanding senior notes ~~due January 2028 (the “5% Senior Notes due 2028”). We used~~on the ~~net proceeds of $744.4~~open market, paying $239.8 million ~~after costs from this offering to redeem our 5% Senior Notes due 2018, reduce borrowings under our credit facilities, and for general partnership purposes.~~

~~On October 30, 2017, we redeemed our outstanding 5% Senior Notes due 2018 at par value~~ plus accrued interest ~~through~~to repurchase $303.3 million of the ~~redemption date.~~notes. The ~~redemption~~repurchases resulted in a ~~non-cash loss from financing activities to~~$61.1 million net gain, which included the write-off ~~$0.2~~of $2.4 million ~~of unamortized~~in related debt issuance ~~costs~~costs.

2020, we amended our accounts receivable securitization facility (the “Securitization Facility”) to decrease the facility size from $400.0 million to $250.0 million to more closely align with our expectations for borrowing needs given current commodity prices and to extend the facility termination date to April 21, 2021.

For a discussion of recent accounting pronouncements that will affect us, see “Recent Accounting Pronouncements” included within Note 3 – Significant Accounting Policies in our Consolidated Financial Statements.

The profitability of our business ~~segments~~ is a function of the difference between: (i) the revenues we receive from our operations, including fee-based revenues from services and revenues from the natural gas, NGLs, crude oil and condensate we sell, and (ii) the costs associated with conducting our operations, including the costs of wellhead natural gas, crude oil and mixed NGLs that we purchase as well as operating, general and administrative costs and the impact of our commodity hedging activities. Because commodity price movements tend to impact both revenues and costs, increases or decreases in our revenues alone are not necessarily indicative of increases or decreases in our profitability. Our contract portfolio, the prevailing pricing environment for crude oil, natural gas and NGLs, the impact of our commodity hedging program and its ability to mitigate exposure to commodity price movements, and the volumes of crude oil, natural gas and NGL throughput on our systems are important factors in determining our profitability. Our profitability is also affected by the NGL content in gathered wellhead natural gas, supply and demand for our products and services, utilization of our assets and changes in our customer mix.

Our profitability is also impacted by fee-based ~~revenues.~~ contracts. Our ~~growth strategy, based on~~growing capital expenditures for pipelines and gathering and processing assets underpinned by fee-based margin, expansion of our downstream facilities, continued focus on adding fee-based margin to our existing ~~facilities~~and future gathering and processing contracts, as well as third-party acquisitions of businesses and assets, ~~has increased~~will continue to increase the ~~percentage~~number of our ~~revenues~~contracts that are fee-based. Fixed fees for services such as gathering and processing, transportation, fractionation, storage, terminaling and crude oil gathering are not directly tied to changes in market prices for commodities. Nevertheless, a change in market dynamics such as available commodity throughput does affect profitability.

Management uses a variety of financial measures and operational measurements to analyze our performance. These include: (1) throughput volumes, facility efficiencies and fuel consumption, (2) operating expenses, (3) capital expenditures and (4) the following non-GAAP measures: gross margin, operating margin, and ~~adjusted~~Adjusted EBITDA.

Our profitability is impacted by our ability to add new sources of natural gas supply and crude oil supply to offset the natural decline of existing volumes from oil and natural gas wells that are connected to our gathering and processing systems. This is achieved by connecting new wells and adding new volumes in existing areas of production, as well as by capturing crude oil and natural gas supplies currently gathered by ~~third-parties.~~third parties. Similarly, our profitability is impacted by our ability to add new sources of mixed NGL supply, ~~typically~~ connected by third-party transportation and Grand Prix, to our Downstream Business fractionation facilities and at times to our export facilities. We fractionate NGLs generated by our gathering and processing plants, as well as by contracting for mixed NGL supply from third-party facilities.

In addition, we seek to increase operating margin by limiting volume losses, reducing fuel consumption and by increasing efficiency. With our gathering systems’ extensive use of remote monitoring capabilities, we monitor the volumes received at the wellhead or central delivery points along our gathering systems, the volume of natural gas received at our processing plant inlets and the volumes of NGLs and residue natural gas recovered by our processing plants. We also monitor the volumes of NGLs received, stored, fractionated and delivered across our logistics assets. This information is tracked through our processing plants and Downstream Business facilities to determine customer settlements for sales and volume related fees for service and helps us increase efficiency and reduce fuel consumption.

As part of monitoring the efficiency of our operations, we measure the difference between the volume of natural gas received at the wellhead or central delivery points on our gathering systems and the volume received at the inlet of our processing plants as an indicator of fuel consumption and line loss. We also track the difference between the volume of natural gas received at the inlet of the processing plant and the NGLs and residue gas produced at the outlet of such plant to monitor the fuel consumption and recoveries of our facilities. Similar tracking is performed for our crude oil gathering and logistics ~~assets.~~assets and our NGL pipelines. These volume, recovery and fuel consumption measurements are an important part of our operational efficiency analysis and safety programs.

Operating expenses are costs associated with the operation of specific assets. Labor, contract services, repair and maintenance, utilities and ad valorem taxes comprise the most significant portion of our operating expenses. These expenses, other than fuel and power, ~~generally~~ remain relatively stable and independent of the volumes through our systems, but may increase with system expansions and will fluctuate depending on the scope of the activities performed during a specific period.

Our capital expenditures are classified as growth capital expenditures, business acquisitions, and maintenance capital expenditures. Growth capital expenditures improve the service capability of the existing assets, extend asset useful lives, increase capacities from existing levels, add capabilities, and reduce costs or enhance revenues. Maintenance capital expenditures are those expenditures that are necessary to maintain the service capability of our existing assets, including the replacement of system components and equipment, which are worn, obsolete or completing their useful life and expenditures to remain in compliance with environmental laws and regulations.

Capital projects associated with growth and maintenance projects are closely monitored. Return on investment is analyzed before a capital project is approved, spending is closely monitored throughout the development of the project, and the subsequent operational performance is compared to the assumptions used in the economic analysis performed for the capital investment approval.

We utilize non-GAAP measures to analyze our performance. Gross margin, operating margin and Adjusted EBITDA are non-GAAP measures. The GAAP measure most directly comparable to these non-GAAP measures is net income (loss) attributable to TRP. These non-GAAP measures should not be considered as an alternative to GAAP net income attributable to TRP and have important limitations as analytical tools. Investors should not consider these measures in isolation or as a substitute for analysis of our results as reported under GAAP. Additionally, because our non-GAAP measures exclude some, but not all, items that affect net income, and are defined differently by different companies within our industry, our definitions may not be comparable with similarly titled measures of other companies, thereby diminishing their utility. Management compensates for the limitations of our non-GAAP measures as analytical tools by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these insights into our decision-making processes.

We define gross margin as revenues less product purchases. It is impacted by volumes and commodity prices as well as by our contract mix and commodity hedging program.

Gathering and Processing segment gross margin consists primarily of revenues from the sale of natural gas, condensate, crude oil and NGLs and fee revenues related to natural gas and crude oil gathering and services, less producer payments and other natural gas and crude oil purchases.of:

Logistics and ~~Marketing~~Transportation segment gross margin consists primarily ofof:

The gross margin impacts of ~~cash flow~~mark-to-market hedge ~~settlements~~unrealized changes in fair value are reported in Other.

We define operating margin as gross margin less operating expenses. Operating margin is an important performance measure of the core profitability of our operations.

Management reviews business segment gross margin and operating margin monthly as a core internal management process. We believe that investors benefit from having access to the same financial measures that management uses in evaluating our operating results. Gross margin and operating margin provide useful information to investors because they are used as supplemental financial measures by management and by external users of our financial statements, including investors and commercial banks, to assess:

Gross margin and operating margin are non-GAAP measures. The GAAP measure most directly comparable to gross margin and operating margin is net income. Gross margin and operating margin are not alternatives to GAAP net income and have important limitations as analytical tools. Investors should not consider gross margin and operating margin in isolation or as a substitute for analysis of our results as reported under GAAP. Because gross margin and operating margin exclude some, but not all, items that affect net income and are defined differently by different companies in our industry, our definitions of gross margin and operating margin may not be comparable with similarly titled measures of other companies, thereby diminishing their utility. Management compensates for the limitations of gross margin and operating margin as analytical tools by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these insights into its decision-making processes.

We define Adjusted EBITDA as net income (loss) attributable to TRP ~~before: interest;~~before interest, income taxes; depreciation and amortization; impairments of goodwill and property, plant and equipment; gains or losses on debt repurchases, redemptions, amendments, exchanges and early debt extinguishments and asset disposals; risk management activities related to derivative instruments, including the cash impact of hedges acquired in the mergers with Atlas Energy L.P. and Atlas Pipeline Partners L.P. in 2015; non-cash compensation on equity grants; transaction costs related to business acquisitions; ~~the Splitter Agreement adjustment; earnings/losses from unconsolidated affiliates net of distributions, distributions from preferred interests, change in contingent consideration and the noncontrolling interest portion of~~taxes, depreciation and amortization, ~~expense.~~and other items that we believe should be adjusted consistent with our core operating performance. The adjusting items are detailed in the Adjusted EBITDA reconciliation table and its footnotes. Adjusted EBITDA is used as a supplemental financial measure by us and by external users of our financial statements such as investors, commercial banks and ~~others. The economic substance behind our use of Adjusted EBITDA is~~others to measure the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness and make distributions to holders of our ~~investors.~~equity interests.

Adjusted EBITDA is a non-GAAP financial measure. The GAAP measure most directly comparable to Adjusted EBITDA is net income (loss) attributable to TRP. Adjusted EBITDA should not be considered as an alternative to GAAP net income. Adjusted EBITDA has important limitations as an analytical tool. Investors should not consider Adjusted EBITDA in isolation or as a substitute for analysis of our results as reported under GAAP. Because Adjusted EBITDA excludes some, but not all, items that affect net income and is defined differently by different companies in our industry, our definition of Adjusted EBITDA may not be comparable to similarly titled measures of other companies, thereby diminishing its utility.

Management compensates for the limitations of Adjusted EBITDA as an analytical tool by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these insights into its decision-making processes.

The following tables reconcile the non-GAAP financial measures used by management to the most directly comparable GAAP measures for the periods ~~indicated.~~indicated:

	Three Months Ended September 30,							Nine Months Ended September 30,							Three Months Ended September 30,						Nine Months Ended September 30,
	2017				2016				2017			2016			2020			2019			2020			2019
	(In millions)														(In millions)
Reconciliation of Net Income (loss) to TRP Operating Margin and Gross Margin:
Reconciliation of Net Income (Loss) to Operating Margin and Gross Margin
Net income (loss)		$	(245.0	)	$	(6.1	)		$	(295.4	)	$	(0.5	)	$	209.1		$	37.5		$	(1,739.5	)	$	70.2
Depreciation and amortization expense			208.3			184.0				602.8			563.6			203.7			244.3			647.3			718.9
General and administrative expense			46.6			44.0				139.4			132.3			56.3			65.6			171.7			212.3
Impairment of property, plant and equipment			378.0			—				378.0			��
Impairment of goodwill			—			—				—			24.0
Interest expense, net			51.9			57.9				169.5			171.2
Income tax expense (benefit)			—			1.0				(4.2	)		—
(Gain) loss on sale or disposition of assets			0.3			4.7				16.6			5.7
Impairment of long-lived assets																—			—			2,442.8			—
Interest (income) expense, net																94.9			84.2			283.0			229.2
Equity (earnings) loss																(18.6	)		(10.0	)		(54.1	)		(15.9	)
(Gain) loss on sale or disposition of business and assets																58.0			0.5			58.0			3.6
Write-down of assets																13.5			17.9			13.5			17.9
(Gain) loss from sale of equity-method investment																—			(65.8	)		—			(65.8	)
(Gain) loss from financing activities			—			—				10.7			(21.4	)		13.7			—			(47.4	)		1.4
Change in contingent considerations																—			—			—			8.8
Other, net			(126.9	)		1.1				(105.7	)		10.7			(0.6	)		—			0.3			0.2
Operating margin			313.2			286.6				911.7			885.6			630.0			374.2			1,775.6			1,180.8
Operating expenses			155.5			143.0				462.6			413.9			181.9			200.2			565.1			600.7
Gross margin		$	468.7		$	429.6			$	1,374.3		$	1,299.5		$	811.9		$	574.4		$	2,340.7		$	1,781.5

Three Months Ended September 30,

Nine Months Ended September 30,

2017

2016

2017

2016

(In millions)

Reconciliation of Net Income (Loss) attributable to TRP to Adjusted EBITDA

Net income (loss) attributable to TRP
$

(254.7
)

$

(10.8
)
$

(321.3
)

$

(14.0
)
Interest expense, net

51.9

57.9

169.5

171.2

Income tax expense (benefit)

—

1.0

(4.2
)

—

Depreciation and amortization expense

208.3

184.0

602.8

563.6

Impairment of property, plant and equipment

378.0

—

378.0

—

Impairment of goodwill

—

—

—

24.0

(Gain) loss on sale or disposition of assets

0.3

4.7

16.6

5.7

(Gain) loss from financing activities

—

—

10.7

(21.4
)
(Earnings) loss from unconsolidated affiliates

(0.2
)

2.2

16.6

11.4

Distributions from unconsolidated affiliates and preferred partner interests, net

4.6

3.8

15.0

12.6

Change in contingent consideration included in Other expense

(126.8
)

(0.3
)

(125.6
)

(0.3
)
Compensation on TRP equity grants

—

—

—

2.2

Transaction costs related to business acquisitions

0.4

—

5.6

—

Splitter Agreement (1)

10.8

—

32.3

—

Risk management activities

2.0

6.2

7.2

18.7

Noncontrolling interests adjustments (2)

(5.0
)

(8.4
)

(13.6
)

(20.5
)
TRP Adjusted EBITDA
$

269.6

$

240.3

$

789.6

$

753.2

	Three Months Ended September 30,						Nine Months Ended September 30,
	2020			2019			2020			2019
	(In millions)
Reconciliation of Net Income (Loss) attributable to TRP to Adjusted EBITDA
Net income (loss) attributable to TRP	$	109.0		$	(39.1	)	$	(1,847.6	)	$	(74.1	)
Interest (income) expense, net		94.9			84.2			283.0			229.2
Depreciation and amortization expense		203.7			244.3			647.3			718.9
Impairment of long-lived assets		—			—			2,442.8			—
(Gain) loss on sale or disposition of business and assets		58.0			0.5			58.0			3.6
Write-down of assets		13.5			17.9			13.5			17.9
(Gain) loss from sale of equity-method investment		—			(65.8	)		—			(65.8	)
(Gain) loss from financing activities (1)		13.7			—			(47.4	)		1.4
Equity (earnings) loss		(18.6	)		(10.0	)		(54.1	)		(15.9	)
Distributions from unconsolidated affiliates and preferred partner interests, net		28.2			14.0			81.6			33.4
Change in contingent considerations		—			—			—			8.8
Risk management activities		(88.3	)		100.7			(214.2	)		100.8
Severance and related benefits (2)		—			—			6.5			—
Noncontrolling interests adjustments (3)		(9.2	)		(8.9	)		(211.7	)		(25.6	)
TRP Adjusted EBITDA	$	404.9		$	337.8		$	1,157.7		$	932.6

The following table and discussion is a summary of our consolidated results of operations:

		Three Months Ended September 30,												Nine Months Ended September 30,												Three Months Ended September 30,												Nine Months Ended September 30,
		2017			2016			2017 vs. 2016						2017			2016			2017 vs. 2016						2020			2019			2020 vs. 2019						2020			2019			2020 vs. 2019
	(In millions, except operating statistics and price amounts)																									(In millions)
Revenues:
Sales of commodities		$	1,871.5		$	1,398.7		$	472.8			34	%	$	5,353.1		$	3,882.9		$	1,470.2			38	%	$	1,840.8		$	1,594.2		$	246.6			15	%	$	4,900.8		$	5,254.8		$	(354.0	)		(7	%)
Fees from midstream services			260.3			253.6			6.7			3	%		759.0			795.5			(36.5	)		(5	%)		274.3			308.3			(34.0	)		(11	%)		786.7			942.4			(155.7	)		(17	%)
Total revenues			2,131.8			1,652.3			479.5			29	%		6,112.1			4,678.4			1,433.7			31	%		2,115.1			1,902.5			212.6			11	%		5,687.5			6,197.2			(509.7	)		(8	%)
Product purchases			1,663.1			1,222.7			440.4			36	%		4,737.8			3,378.9			1,358.9			40	%		1,303.2			1,328.1			(24.9	)		(2	%)		3,346.8			4,415.7			(1,068.9	)		(24	%)
Gross margin (1)			468.7			429.6			39.1			9	%		1,374.3			1,299.5			74.8			6	%		811.9			574.4			237.5			41	%		2,340.7			1,781.5			559.2			31	%
Operating expenses			155.5			143.0			12.5			9	%		462.6			413.9			48.7			12	%		181.9			200.2			(18.3	)		(9	%)		565.1			600.7			(35.6	)		(6	%)
Operating margin (1)			313.2			286.6			26.6			9	%		911.7			885.6			26.1			3	%		630.0			374.2			255.8			68	%		1,775.6			1,180.8			594.8			50	%
Depreciation and amortization expense			208.3			184.0			24.3			13	%		602.8			563.6			39.2			7	%		203.7			244.3			(40.6	)		(17	%)		647.3			718.9			(71.6	)		(10	%)
General and administrative expense			46.6			44.0			2.6			6	%		139.4			132.3			7.1			5	%		56.3			65.6			(9.3	)		(14	%)		171.7			212.3			(40.6	)		(19	%)
Impairment of property, plant and equipment			378.0			—			378.0			—			378.0			—			378.0			—
Impairment of goodwill			—			—			—			—			—			24.0			(24.0	)		(100	%)
Impairment of long-lived assets																											—			—			—			—			2,442.8			—			2,442.8			—
Other operating (income) expense			0.6			4.9			(4.3	)		(88	%)		17.2			6.1			11.1			182	%		72.2			18.4			53.8			292	%		73.8			21.7			52.1			240	%
Income from operations			(320.3	)		53.7			(374.0	)	NM				(225.7	)		159.6			(385.3	)		(241	%)
Income (loss) from operations																											297.8			45.9			251.9		NM				(1,560.0	)		227.9			(1,787.9	)	NM
Interest expense, net			(51.9	)		(57.9	)		6.0			10	%		(169.5	)		(171.2	)		1.7			1	%		(94.9	)		(84.2	)		(10.7	)		13	%		(283.0	)		(229.2	)		(53.8	)		23	%
Equity earnings (loss)			0.2			(2.2	)		2.4			109	%		(16.6	)		(11.4	)		(5.2	)		46	%		18.6			10.0			8.6			86	%		54.1			15.9			38.2			240	%
Gain (loss) from financing activities			—			—			—			—			(10.7	)		21.4			(32.1	)		(150	%)		(13.7	)		—			(13.7	)		—			47.4			(1.4	)		48.8		NM
Gain (loss) from sale of equity-method investment																											—			65.8			(65.8	)		(100	%)		—			65.8			(65.8	)		(100	%)
Change in contingent considerations			126.8			0.3			126.5		NM				125.6			0.3			125.3		NM				—			—			—			—			—			(8.8	)		8.8			100	%
Other income (expense), net			0.2			1.0			(0.8	)		(80	%)		(2.7	)		0.8			(3.5	)	NM
Income tax (expense) benefit			—			(1.0	)		1.0			100	%		4.2			—			4.2			—
Other, net																											1.3			—			1.3			—			2.0			—			2.0			—
Net income (loss)			(245.0	)		(6.1	)		(238.9	)	NM				(295.4	)		(0.5	)		(294.9	)	NM				209.1			37.5			171.6		NM				(1,739.5	)		70.2			(1,809.7	)	NM
Less: Net income attributable to noncontrolling interests			9.7			4.7			5.0			106	%		25.9			13.5			12.4			92	%
Less: Net income (loss) attributable to noncontrolling interests																											100.1			76.6			23.5			31	%		108.1			144.3			(36.2	)		(25	%)
Net income (loss) attributable to Targa Resources Partners LP		$	(254.7	)	$	(10.8	)	$	(243.9	)	NM			$	(321.3	)	$	(14.0	)	$	(307.3	)	NM			$	109.0		$	(39.1	)	$	148.1		NM			$	(1,847.6	)	$	(74.1	)	$	(1,773.5	)	NM
Financial and operating data:
Financial data:
Adjusted EBITDA (1)		$	269.6		$	240.3		$	29.3			12	%	$	789.6		$	753.2		$	36.4			5	%	$	404.9		$	337.8		$	67.1			20	%	$	1,157.7		$	932.6		$	225.1			24	%
Capital expenditures			378.7			134.6			244.1			181	%		987.7			426.5			561.2			132	%
Business acquisition (2)			—			—			—			—			987.1			—			987.1			—
Operating statistics: (3)
Crude oil gathered, Badlands, MBbl/d			108.7			103.9			4.8			5	%		111.6			105.7			5.9			6	%
Crude oil gathered, Permian, MBbl/d (4)			35.7			—			35.7			—			24.6			—			24.6			—
Plant natural gas inlet, MMcf/d (5)(6)			3,621.4			3,356.6			264.8			8	%		3,418.5			3,422.3			(3.8	)		—
Gross NGL production, MBbl/d			346.2			310.4			35.8			12	%		318.9			305.4			13.5			4	%
Export volumes, MBbl/d (7)			154.5			156.7			(2.2	)		(1	%)		175.5			173.0			2.5			1	%
Natural gas sales, BBtu/d (6)(8)			2,054.1			1,993.0			61.1			3	%		1,942.5			1,975.4			(32.9	)		(2	%)
NGL sales, MBbl/d (8)			497.6			497.3			0.3			—			501.6			520.6			(19.0	)		(4	%)
Condensate sales, MBbl/d			11.4			10.0			1.4			14	%		11.5			10.3			1.2			12	%

NM Due to a low denominator, the noted percentage change is disproportionately high and as a result, considered not meaningful.

Three Months Ended September 30, ~~2017~~2020 Compared to Three Months Ended September 30, ~~2016~~2019

The increase in commodity sales ~~was primarily due to~~reflects higher ~~commodity~~NGL and natural gas prices ($~~443.3~~133.5 million), higher NGL, condensate and petroleum products volumes ($100.7 million) and ~~increased volumes~~the favorable impact of hedges ($~~40.0~~171.0 million), partially offset by ~~the impact of hedge settlements~~lower crude marketing and natural gas volumes ($~~10.5~~128.9 million)~~. Fee-based~~ and ~~other revenues increased~~lower condensate and petroleum product prices ($29.6 million).

The decrease in fees from midstream services is primarily due to ~~higher~~new commercial arrangements for volumes effective in January 2020, which resulted in a change from net presentation as fees from midstream services to gross presentation as sales of commodities and product purchases, and lower gas processing ~~fees.~~volumes, partially offset by increased export and terminaling and storage volumes.

The ~~increase~~decrease in product purchases ~~was primarily due to~~reflects lower crude marketing volumes associated with the ~~impact of higher commodity prices and increased volumes.~~

In the third quarter of 2017, we experienced limited impacts to our operations as a result of Hurricane Harvey. We incurred: (i) flooding at our Mont Belvieu facilities that resulted in temporary constraints on the receipt of NGLs and the temporary removal of fractionators from service at CBF, resulting in increased levels of mixed NGLs in storage and (ii) the shut-in of our Galena Park Marine Terminal for approximately one week due to the closuresale of the ~~Houston Ship Channel. Our operating margin for the three months ended September 30, 2017,~~Delaware crude system, which was ~~reduced~~effective December 1, 2019, and lower natural gas volumes, partially offset by ~~approximately $10 million as a result of Hurricane Harvey, comprised of the impact on the Mont Belvieu~~higher NGL and Galena Park Marine Terminal facilities along with lost operating margin associated with temporary production disruptions for a limited number of our producer and downstream customers. We expect to recover approximately $7 million of the reduced operating margin during the fourth quarter of 2017 when the additional stored volumes of mixed NGLs are fractionated and sold. No property insurance claims are expected as a result of the storm as damage to our facilities was minimal. Business interruption insurance claims related to the storm are expected to be minimal.natural gas prices.

~~The higher~~Higher operating margin and gross margin in ~~2017 reflects~~2020 reflect increased segment ~~margin~~ results for Gathering and Processing ~~partially offset by decreased~~and Logistics and Marketing segment margins. Operating expenses increased compared to 2016 due to the impact of the Permian Acquisition, plant and system expansions in the Permian region and the June 2017 commencement of operations of the Raptor Plant at SouthTX in the Gathering and Processing segment, and higher labor, repairs and maintenance expense in the Logistics and Marketing segment.Transportation. See “—Results of Operations—By Reportable Segment” for additional information regarding changes in operating margin and gross margin on a segment basis.

Depreciation and amortization expense ~~increased~~decreased primarily due to a lower depreciable base associated with assets that were impaired during the ~~impact~~first quarter of 2020 and the sale of the Delaware crude system, which was effective December 1, 2019. The decrease in depreciation and amortization expense was partially offset by higher depreciation related to major growth capital projects placed in service, including Train 7 and the additional processing plants and associated infrastructure in the Permian ~~Acquisition and other growth investments.~~Basin.

General and administrative expense decreased due to cost reduction measures resulting in lower compensation and benefits and non-labor expenses, partially offset by an increase in insurance costs.

Other operating (income) expense in 2020 consisted primarily of a loss associated with the reduction in the carrying value of our assets in Channelview, Texas in connection with the October 2020 Saleand write-down of certain assets to their recoverable amounts. Other operating (income) expense in 2019 consisted primarily of a loss associated with the write-down of certain assets to their recoverable amounts.

Interest expense, net, increased due to lower capitalized interest resulting from lower growth capital investments and higher average borrowings.

The increase in equity earnings is primarily due to higher ~~compensation~~earnings from our investments in GCX and ~~benefits,~~Little Missouri 4 LLC (“Little Missouri 4”), partially offset by lower ~~professional services.~~

~~The impairment of property, plant and equipment in 2017 reflects~~ ~~an impairment as of September 30, 2017 of gas processing facilities and gathering systems associated with our North Texas operations in the Gathering and Processing segment. The impairment is a result of our current assessment that forecasted undiscounted future net cash flows~~earnings from operations, while positive, will not be sufficient to recover the existing total net book value of the underlying assets. Given the current price environment, Targa is projecting a continuing decline in natural gas production across the Barnett Shale in North Texas due in part to producers pursuing more attractive opportunities in other basins.

~~Net interest expense decreased primarily due to the impact of lower average outstanding borrowings during 2017, partially offset by higher non-cash interest expense related to the mandatorily redeemable preferred interests that is revalued quarterly at the estimated redemption value as of the reporting date~~Gulf Coast Fractionators LP (“GCF”).

During ~~2017,~~the third quarter of 2020, we ~~recorded other income~~redeemed the 6¾% Senior Notes due 2024, resulting in a $13.7 million net loss from financing activities.

During the third quarter of ~~$126.8 million resulting from~~2019, we closed on the ~~change in the fair value~~sale of contingent considerations, substantially all of which was due to the reduction in fair value as of September 30, 2017 of the Permian Acquisition contingent consideration liability, which is based on a multiple of gross margin realized during the first two annual periods after the acquisition date. The decrease in fair value was primarily related to reductions in actual and forecasted volumes and gross margin as a result of changes in producers’ drilling activity in the region since the acquisition date. Such changes in estimated fair value of the contingent consideration are attributable to events and circumstancesan equity-method investment that occurred after the acquisition date, and as such are recognized in earnings. The fair value of the contingent consideration represents our current view of the future payment amounts, and may decrease or increase until the settlement dates, resultingresulted in the recognition of ~~additional other income (expense).~~a gain of $65.8 million.

Net income attributable to noncontrolling interests was higher in ~~2017~~2020 primarily due to ~~increased earnings at our joint ventures as compared with 2016.~~income allocated to noncontrolling interest holders in the Grand Prix Joint Venture, Targa GCX Pipeline LLC (“GCX DevCo JV”) and the Centrahoma Joint Venture.

Nine Months Ended September 30, ~~2017~~2020 Compared to Nine Months Ended September 30, ~~2016~~2019

The ~~increase~~decrease in commodity sales ~~was primarily due to higher commodity~~reflects lower NGL, condensate, natural gas and petroleum product prices ($~~1,600.9~~1,112.5 million) and ~~increased petroleum products and condensate~~lower crude marketing volumes ($~~44.0~~254.7 million), partially offset by ~~decreased~~higher NGL, ~~and~~condensate, natural gas ~~sales~~and petroleum product volumes ($~~126.0~~664.3 million), the favorable impact of hedges ($345.1 million) and ~~the impact of hedge settlements~~higher crude marketing prices ($~~48.7~~3.8 million). ~~Fee-based and other revenues decreased~~

The decrease in fees from midstream services is primarily due to new commercial arrangements for volumes effective in January 2020, which resulted in a change from net presentation as fees from midstream services to gross presentation as sales of commodities and product purchases, and lower ~~export fees,~~gas processing volumes, partially offset by ~~increases in gas processing~~increased export and ~~crude gathering fees.~~terminaling and storage volumes.

The ~~increase~~decrease in product purchases reflects lower NGL, condensate, natural gas and petroleum product prices, as well as lower crude marketing volumes associated with the sale of the Delaware crude system, which was ~~primarily due to the impact of higher commodity prices,~~effective December 1, 2019, partially offset by ~~decreased~~higher NGL, condensate, natural gas and petroleum product volumes.

In the third quarter of 2017, we experienced limited impacts to our operations as a result of Hurricane Harvey. Our operating margin for the nine months ended September 30, 2017, was reduced by approximately $10 million as a result of Hurricane Harvey, comprised

of the impact on the Mont Belvieu and Galena Park Marine Terminal facilities along with lost operating margin associated with temporary production disruptions for a limited number of our producer and chemical customers. We expect to recover approximately $7 million of the reduced operating margin during the fourth quarter of 2017 when the additional stored volumes of mixed NGLs are fractionated and sold.

~~The higher~~Higher operating margin and gross margin in ~~2017 reflects~~2020 reflect increased segment ~~margin~~ results for Gathering and Processing ~~partially offset by decreased~~and Logistics and ~~Marketing segment margins.~~ Operating expenses increased compared to 2016 due to the impact of the Permian Acquisition, plant and system expansions in the Permian region and the June 2017 commencement of operations of the Raptor Plant at SouthTX in the Gathering and Processing segment, and higher fuel and power that is largely passed through in the Logistics and Marketing segment.Transportation. See “—Results of Operations—By Reportable Segment” for additional information regarding changes in operating margin and gross margin on a segment basis.

Depreciation and amortization expense ~~increased~~decreased primarily due to a lower depreciable base associated with assets that were impaired during the ~~impact~~first quarter of ~~the March 2017 Permian Acquisition~~2020 and the ~~impact~~sale of ~~other~~the Delaware crude system, which was effective December 1, 2019. The decrease in depreciation and amortization expense was partially offset by higher depreciation related to major growth ~~investments,~~capital projects placed in service, including ~~CBF~~ Train ~~5 that went into service~~7 and the additional processing plants and associated infrastructure in the ~~second quarter of 2016 and the Raptor Plant at SouthTX that went into service in the second quarter of 2017.~~Permian Basin.

General and administrative expense ~~increased primarily~~decreased due to ~~higher~~cost reduction measures resulting in lower compensation and benefits and non-labor expenses, partially offset by ~~lower professional services.~~an increase in insurance costs.

The impairment ~~of property, plant and equipment in 2017 reflects~~ ancharge is primarily associated with the partial impairment of gas processing facilities and gathering systems ~~associated with our North Texas operations~~ in ~~the Gathering and Processing segment (described above).~~

In the first quarter of ~~2016, we recognized a $24.0 million adjustment to a provisional~~2020 associated with our Mid-Continent operations and full impairment of ~~goodwill recorded~~our Coastal operations - all of which are in our Gathering and Processing segment. Based on then-current market conditions, our first quarter impairment assessment projected further decline in natural gas production across the Mid-Continent and Gulf of Mexico. We did not recognize any impairments of long-lived assets during the nine months ended September 30, 2019. We may identify additional triggering events in the ~~fourth quarter~~future, which will require additional evaluations of ~~2015 related to goodwill acquired~~the recoverability of the carrying value of our long-lived assets and may result in ~~the mergers with Atlas Energy L.P. and Atlas Pipeline Partners L.P. in 2015 (collectively the “Atlas mergers’).~~future impairments.

Other operating (income) expense in ~~2017 is~~2020 consisted primarily ~~due to~~of a loss associated with the reduction in the carrying value of our ~~ownership interest~~assets in ~~the Venice Gathering System~~Channelview, Texas in connection with the ~~April 2017 sale.~~ October 2020 Sale and write-down of certain assets to their recoverable amounts. Other operating (income) expense in ~~2016~~2019 consisted primarily of a loss associated with the write-down of certain assets to their recoverable amounts.

Interest expense, net, increased due to lower capitalized interest resulting from lower growth capital investments and higher average borrowings.

The increase in equity earnings is primarily due to ~~the loss on decommissioning two storage wells at~~higher earnings from our ~~Hattiesburg facility~~investments in GCX and ~~an acid gas injection well at our Versado facility.~~

~~Net interest expense in 2017 decreased as compared with 2016 primarily due to lower average outstanding borrowings during 2017,~~Little Missouri 4, partially offset by ~~higher non-cash~~lower earnings from GCF.

During the nine months ended September 30, 2020, we repurchased a portion of its outstanding senior notes on the open market and redeemed the 6¾% Senior Notes due 2024, paying $831.0 million plus accrued interest ~~expense related~~ to ~~the mandatorily redeemable preferred interests that is revalued quarterly at the estimated redemption value as~~repurchase $883.4 million of the ~~reporting date.~~notes, resulting in a $47.4 million net gain from financing activities.

~~Higher equity losses in 2017 reflects a $12.0 million loss provision due to~~During the ~~impairment~~third quarter of ~~our~~2019, we closed on the sale of an equity-method investment that resulted in the ~~T2 EF Cogen joint venture, partially offset by increased equity earnings at Gulf Coast Fractionators.~~

~~During 2017, we recorded a loss from financing activities~~recognition of ~~$10.7 million on the redemption of the outstanding~~ ~~6⅜% Senior~~ ~~Notes, whereas in 2016 we recorded~~ a gain of ~~$21.4 million on open market debt repurchases.~~

During 2017, we recorded other income of $125.6 million resulting from the change in the fair value of contingent considerations, substantially all of which was due to the reduction in fair value as of September 30, 2017 of the Permian Acquisition contingent consideration liability.

~~The increase in income tax benefit was primarily due to a Texas Margin Tax refund in the first quarter of 2017.~~$65.8 million.

Net income attributable to noncontrolling interests was ~~higher~~lower in ~~2017~~2020 primarily due to ~~our October 2016 acquisition~~the allocation of impairment losses recognized during the ~~37%~~first quarter of 2020 to noncontrolling interest ~~of Versado that we did not already own. Further, earnings at our joint ventures increased as compared with 2016.~~holders, partially offset by higher income allocated to noncontrolling interest holders in Targa Badlands LLC (“Targa Badlands”), the DevCo Joint Ventures and the Grand Prix Joint Venture.

Three Months Ended September 30,

Nine Months Ended September 30,

2017

2016

2017 vs. 2016

2017

2016

2017 vs. 2016

Gross margin
$

289.7

$

231.7

$

58.0

25
%

$

817.1

$

648.0

$

169.1

26
%
Operating expenses

91.4

82.3

9.1

11
%

267.8

243.9

23.9

10
%
Operating margin
$

198.3

$

149.4

$

48.9

33
%

$

549.3

$

404.1

$

145.2

36
%
Operating statistics (1):

Plant natural gas inlet, MMcf/d (2),(3)

SAOU (4)

324.6

262.5

62.1

24
%

304.1

255.1

49.0

19
%
WestTX

607.5

506.0

101.5

20
%

560.8

480.8

80.0

17
%
Total Permian Midland

932.1

768.5

163.6

864.9

735.9

129.0

Sand Hills (4)

193.0

140.9

52.1

37
%

171.6

142.6

29.0

20
%
Versado

210.9

180.6

30.3

17
%

202.0

176.5

25.5

14
%
Total Permian Delaware

403.9

321.5

82.4

373.6

319.1

54.5

Total Permian

1,336.0

1,090.0

246.0

1,238.5

1,055.0

183.5

SouthTX

330.1

218.0

112.1

51
%

242.1

219.7

22.4

10
%
North Texas

261.8

315.2

(53.4
)

(17
%)

273.7

323.4

(49.7
)

(15
%)
SouthOK

515.2

469.8

45.4

10
%

478.5

466.1

12.4

3
%
WestOK

367.1

434.4

(67.3
)

(15
%)

382.5

455.6

(73.1
)

(16
%)
Total Central

1,474.2

1,437.4

36.8

1,376.8

1,464.8

(88.0
)

Badlands (5)

60.9

53.8

7.1

13
%

53.1

52.9

0.2

—

Total Field

2,871.1

2,581.2

289.9

2,668.4

2,572.7

95.7

Coastal

750.5

775.5

(25.0
)

(3
%)

750.1

849.7

(99.6
)

(12
%)

Total

3,621.6

3,356.7

264.9

8
%

3,418.5

3,422.4

(3.9
)

—

Gross NGL production, MBbl/d (3)

SAOU (4)

38.7

32.8

5.9

18
%

36.6

31.4

5.2

17
%
WestTX

84.1

67.6

16.5

24
%

75.2

60.7

14.5

24
%
Total Permian Midland

122.8

100.4

22.4

111.8

92.1

19.7

Sand Hills (4)

21.0

15.2

5.8

38
%

18.6

15.0

3.6

24
%
Versado

25.3

21.8

3.5

16
%

23.8

21.3

2.5

12
%
Total Permian Delaware

46.3

37.0

9.3

42.4

36.3

6.1

Total Permian

169.1

137.4

31.7

154.2

128.4

25.8

SouthTX

35.4

20.9

14.5

69
%

25.2

25.1

0.1

—

North Texas

29.3

36.2

(6.9
)

(19
%)

30.8

36.3

(5.5
)

(15
%)
SouthOK

42.7

42.4

0.3

1
%

40.7

39.3

1.4

4
%
WestOK

20.7

27.2

(6.5
)

(24
%)

22.3

27.9

(5.6
)

(20
%)
Total Central

128.1

126.7

1.4

119.0

128.6

(9.6
)

��

Badlands

9.0

7.8

1.2

15
%

7.4

7.5

(0.1
)

(1
%)
Total Field

306.2

271.9

34.3

280.6

264.5

16.1

Coastal

40.0

38.6

1.4

4
%

38.2

41.0

(2.8
)

(7
%)

Total

346.2

310.5

35.7

11
%

318.8

305.5

13.3

4
%
Crude oil gathered, Badlands, MBbl/d

108.7

103.9

4.8

5
%

111.6

105.7

5.9

6
%
Crude oil gathered, Permian, MBbl/d (4)

35.7

—

35.7

—

24.6

—

24.6

—

Natural gas sales, BBtu/d (3)

1,738.5

1,617.6

120.9

7
%

1,647.8

1,636.8

11.0

1
%
NGL sales, MBbl/d

244.4

248.4

(4.0
)

(2
%)

240.4

241.3

(0.9
)

-

Condensate sales, MBbl/d

11.4

9.7

1.7

18
%

11.4

10.0

1.4

14
%
Average realized prices (6):

Natural gas, $/MMBtu

2.58

2.49

0.09

4
%

2.71

1.96

0.75

38
%
NGL, $/gal

0.56

0.36

0.20

56
%

0.51

0.33

0.18

55
%
Condensate, $/Bbl

42.69

38.29

4.40

11
%

43.42

34.18

9.24

27
%

	Three Months Ended September 30,									Nine Months Ended September 30,
	2020		2019		2020 vs. 2019					2020		2019		2020 vs. 2019
	(In millions, except operating statistics and price amounts)
Gross margin	$	362.9	$	366.7	$	(3.8	)	(1	%)	$	1,071.4	$	1,092.0	$	(20.6	)	(2	%)
Operating expenses		101.9		120.2		(18.3	)	(15	%)		317.7		375.2		(57.5	)	(15	%)
Operating margin	$	261.0	$	246.5	$	14.5		6	%	$	753.7	$	716.8	$	36.9		5	%
Operating statistics (1):
Plant natural gas inlet, MMcf/d (2),(3)
Permian Midland (4)		1,811.5		1,513.9		297.6		20	%		1,722.1		1,421.3		300.8		21	%
Permian Delaware		758.1		629.4		128.7		20	%		712.4		552.2		160.2		29	%
Total Permian		2,569.6		2,143.3		426.3					2,434.5		1,973.5		461.0

SouthTX (5)		233.6		328.6		(95.0	)	(29	%)		261.5		335.3		(73.8	)	(22	%)
North Texas		197.8		228.2		(30.4	)	(13	%)		206.3		227.6		(21.3	)	(9	%)
SouthOK (6)		386.9		590.8		(203.9	)	(35	%)		463.3		606.1		(142.8	)	(24	%)
WestOK		233.6		329.2		(95.6	)	(29	%)		258.7		335.2		(76.5	)	(23	%)
Total Central		1,051.9		1,476.8		(424.9	)				1,189.8		1,504.2		(314.4	)

Badlands (7),(8)		137.0		120.8		16.2		13	%		136.1		103.4		32.7		32	%
Total Field		3,758.5		3,740.9		17.6					3,760.4		3,581.1		179.3

Coastal		522.8		764.9		(242.1	)	(32	%)		672.9		779.9		(107.0	)	(14	%)

Total		4,281.3		4,505.8		(224.5	)	(5	%)		4,433.3		4,361.0		72.3		2	%
NGL production, MBbl/d (3)
Permian Midland (4)		253.0		216.5		36.5		17	%		247.6		199.8		47.8		24	%
Permian Delaware		105.3		82.3		23.0		28	%		97.1		71.4		25.7		36	%
Total Permian		358.3		298.8		59.5					344.7		271.2		73.5

SouthTX (5)		29.2		41.5		(12.3	)	(30	%)		28.7		44.0		(15.3	)	(35	%)
North Texas		23.7		27.3		(3.6	)	(13	%)		24.5		26.9		(2.4	)	(9	%)
SouthOK (6)		45.9		69.5		(23.6	)	(34	%)		54.6		65.4		(10.8	)	(17	%)
WestOK		19.3		19.2		0.1		1	%		21.2		22.4		(1.2	)	(5	%)
Total Central		118.1		157.5		(39.4	)				129.0		158.7		(29.7	)

Badlands (8)		17.0		14.0		3.0		21	%		16.3		12.2		4.1		34	%
Total Field		493.4		470.3		23.1					490.0		442.1		47.9

Coastal		32.5		45.4		(12.9	)	(28	%)		41.5		47.0		(5.5	)	(12	%)

Total		525.9		515.7		10.2		2	%		531.5		489.1		42.4		9	%
Crude oil, Badlands, MBbl/d		146.4		164.3		(17.9	)	(11	%)		160.4		167.0		(6.6	)	(4	%)
Crude oil, Permian, MBbl/d (9)		44.6		95.2		(50.6	)	(53	%)		45.3		86.1		(40.8	)	(47	%)
Natural gas sales, BBtu/d (3),(10)		2,032.3		2,056.6		(24.3	)	(1	%)		2,079.3		2,011.2		68.1		3	%
NGL sales, MBbl/d (3),(10)		389.5		398.0		(8.5	)	(2	%)		406.0		382.4		23.6		6	%
Condensate sales, MBbl/d		13.6		11.0		2.6		24	%		16.1		12.2		3.9		32	%
Average realized prices - inclusive of hedges (11):
Natural gas, $/MMBtu		1.34		1.13		0.21		19	%		1.10		1.31		(0.21	)	(16	%)
NGL, $/gal		0.29		0.28		0.01		4	%		0.24		0.35		(0.11	)	(31	%)
Condensate, $/Bbl		43.49		50.23		(6.74	)	(13	%)		38.56		49.49		(10.93	)	(22	%)

~~Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016~~

The increase in gross margin was primarily due to higher commodity prices and higher Permian volumes, including those associated with the Permian Acquisition. Field Gathering and Processing inlet volume increases included all areas in the Permian region, as well as SouthTX, Badlands and SouthOK, partially offset by decreases at WestOK and North Texas. The inlet volume decrease for Coastal Gathering and Processing, which generates significantly lower unit margins, partially offset the Field Gathering and Processing inlet volume increase. NGL production and natural gas sales increased primarily due to increased Field Gathering and Processing inlet volumes. The decrease in NGL sales was primarily due to the deferral to the fourth quarter of 2017 of NGL sales impacted by the temporary operational issues related to Hurricane Harvey. Total crude oil gathered volumes increased in the Permian region due to the Permian Acquisition. Total Badlands crude oil gathered volumes and natural gas volumes increased primarily due to system expansions.

The increase in operating expenses was primarily driven by the inclusion of the Permian Acquisition, plant and system expansions in the Permian region and the June 2017 commencement in operations of the Raptor Plant at SouthTX.

~~Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016~~

The increase in gross margin was primarily due to higher commodity prices and higher Permian volumes including those associated with the Permian Acquisition. Field Gathering and Processing inlet volume increases included all areas in the Permian region, as well as SouthTX and SouthOK, partially offset by decreases at WestOK and North Texas. The inlet volume decrease for Coastal Gathering and Processing, which generates significantly lower unit margins, more than offset the Field Gathering and Processing inlet volume increase. Despite overall lower inlet volumes, NGL production increased primarily due to increased plant recoveries including additional ethane recovery. Third quarter NGL sales were reduced due to the deferral to the fourth quarter of 2017 of NGL sales impacted by the temporary operational issues related to Hurricane Harvey. Natural gas sales increased primarily due to increased Field Gathering and Processing inlet volumes. Total crude oil gathered volumes increased in the Permian region due to the Permian Acquisition. Total Badlands crude oil gathered increased due to system expansions. Badlands natural gas volumes were relatively flat primarily due to the impact of the severe winter weather in the first quarter of 2017.

~~The table below provides a reconciliation between gross operating statistics and the actual reported operating statistics for the Field portion of the Gathering and Processing segment:~~

Three Months Ended September 30, 2017

Operating statistics:

Plant natural gas inlet, MMcf/d (1),(2)

Gross Volume (3)

Ownership %

Net Volume (3)

Actual Reported

SAOU (4)

324.6

100
%

324.6

324.6

WestTX (5) (6)

834.5

73
%

607.5

607.5

Total Permian Midland

1,159.1

932.1

932.1

Sand Hills (4)

193.0

100
%

193.0

193.0

Versado (7)

210.9

100
%

210.9

210.9

Total Permian Delaware

403.9

403.9

403.9

Total Permian

1,563.0

1,336.0

1,336.0

SouthTX

330.1

Varies (8) (9)

260.0

330.1

North Texas

261.8

100
%

261.8

261.8

SouthOK

515.2

Varies (10)

412.1

515.2

WestOK

367.1

100
%

367.1

367.1

Total Central

1,474.2

1,301.0

1,474.2

Badlands (11)

60.9

100
%

60.9

60.9

Total Field

3,098.1

2,697.9

2,871.1

Gross NGL production, MBbl/d (2)

SAOU (4)

38.7

100
%

38.7

38.7

WestTX (5) (6)

115.5

73
%

84.1

84.1

Total Permian Midland

154.2

122.8

122.8

Sand Hills (4)

21.0

100
%

21.0

21.0

Versado (7)

25.3

100
%

25.3

25.3

Total Permian Delaware

46.3

46.3

46.3

Total Permian

200.5

169.1

169.1

SouthTX

35.4

Varies (8) (9)

28.6

35.4

North Texas

29.3

100
%

29.3

29.3

SouthOK

42.7

Varies (10)

34.6

42.7

WestOK

20.7

100
%

20.7

20.7

Total Central

128.1

113.2

128.1

Badlands

9.0

100
%

9.0

9.0

Total Field

337.6

291.3

306.2

Three Months Ended September 30, 2016

Operating statistics:

Plant natural gas inlet, MMcf/d (1),(2)

Gross Volume (3)

Ownership %

Net Volume (3)

Actual Reported

SAOU

262.5

100
%

262.5

262.5

WestTX (4)

695.0

73
%

506.0

506.0

Total Permian Midland

957.5

768.5

768.5

Sand Hills

140.9

100
%

140.9

140.9

Versado (5)

180.6

63
%

113.8

180.6

Total Permian Delaware

321.5

254.7

321.5

Total Permian

1,279.0

1,023.2

1,090.0

SouthTX

218.0

Varies (6)

205.6

218.0

North Texas

315.2

100
%

315.2

315.2

SouthOK

469.8

Varies (7)

392.8

469.8

WestOK

434.4

100
%

434.4

434.4

Total Central

1,437.4

1,348.0

1,437.4

Badlands (8)

53.8

100
%

53.8

53.8

Total Field

2,770.2

2,425.0

2,581.2

Gross NGL production, MBbl/d (2)

SAOU

32.8

100
%

32.8

32.8

WestTX (4)

92.9

73
%

67.6

67.6

Total Permian Midland

125.7

100.4

100.4

Sand Hills

15.2

100
%

15.2

15.2

Versado (5)

21.8

��
63
%

13.7

21.8

Total Permian Delaware

37.0

28.9

37.0

Total Permian

162.7

129.3

137.4

SouthTX

20.9

Varies (6)

19.7

20.9

North Texas

36.2

100
%

36.2

36.2

SouthOK

42.4

Varies (7)

39.1

42.4

WestOK

27.2

100
%

27.2

27.2

Total Central

126.7

122.2

126.7

Badlands

7.8

100
%

7.8

7.8

Total Field

297.2

259.3

271.9

The following table presents the realized commodity hedge gain/loss attributable to our equity volumes that are included in the gross margin of Gathering and ~~Marketing Segment~~Processing segment:

Three Months Ended September 30,

Nine Months Ended
September 30,

2017

2016

2017 vs. 2016

2017

2016

2017 vs. 2016

(In millions)

Gross margin

$

180.0

$

186.7

$

(6.7
)

(4
%)

$

553.3

$

594.6

$

(41.3
)

(7
%)
Operating expenses

64.1

60.7

3.4

6
%

194.8

170.0

24.8

15
%
Operating margin

$

115.9

$

126.0

$

(10.1
)

(8
%)

$

358.5

$

424.6

$

(66.1
)

(16
%)
Operating statistics MBbl/d (1):

Fractionation volumes (2)(3)

329.3

313.2

16.1

5
%

324.3

312.8

11.5

4
%
LSNG treating volumes (2)

27.2

25.6

1.6

6
%

31.6

23.3

8.3

36
%
Benzene treating volumes (2)

16.1

20.2

(4.1
)

(20
%)

20.5

21.4

(0.9
)

(4
%)
Export volumes, MBbl/d (4)

154.5

156.7

(2.2
)

(1
%)

175.5

173.0

2.5

1
%
NGL sales, MBbl/d

463.4

452.4

11.0

2
%

468.1

466.3

1.8

—

Average realized prices:

NGL realized price, $/gal

$

0.67

$

0.46

$

0.21

46
%

$

0.64

$

0.45

$

0.19

42
%

	Three Months Ended September 30, 2020						Three Months Ended September 30, 2019
	(In millions, except volumetric data and price amounts)
	Volume Settled		Price Spread (1)		Gain (Loss)		Volume Settled		Price Spread (1)			Gain (Loss)
Natural gas (BBtu)		17.5	$	0.20	$	3.5		18.8	$	1.07		$	20.1
NGL (MMgal)		126.4		0.08		10.5		110.0		0.17			18.5
Crude oil (MBbl)		0.5		16.75		8.0		0.4		(1.76	)		(0.7	)
					$	22.0						$	37.9

	Nine Months Ended September 30, 2020						Nine Months Ended September 30, 2019
	(In millions, except volumetric data and price amounts)
	Volume Settled		Price Spread (1)		Gain (Loss)		Volume Settled		Price Spread (1)			Gain (Loss)
Natural gas (BBtu)		50.6	$	0.55	$	27.7		47.0	$	1.29		$	60.6
NGL (MMgal)		322.1		0.15		49.7		252.1		0.11			27.9
Crude oil (MBbl)		1.4		19.72		27.7		1.1		(2.28	)		(2.6	)
					$	105.1						$	85.9

Three Months Ended September 30, 2020 Compared to Three Months Ended September 30, 2019

Gathering and Processing segment gross margin contributions, attributable to higher system volumes and fee-based margin in the Permian region, were offset by lower volumes in the Central region and lower realized hedge gains. In the Permian, inlet volumes and NGL production increased due to production from new wells and the addition of the Pembrook and Falcon plants in 2019 and the Peregrine and Gateway plants in 2020. Lower volumes in the Central region were attributable to temporary shut-ins and reduced producer activity. In the Badlands, natural gas purchased volumes and NGL production increased due to production from new wells and the incremental processing capacity available with the commencement of operations at the Little Missouri 4 Plant in the third quarter of 2019. In the Coastal region, volumes were lower due to continued low producer activity and the effects of multiple Gulf Coast hurricanes in the third quarter of 2020, which necessitated temporary shutdowns of certain facilities in Louisiana. Total crude oil volumes decreased in the Badlands due to reduced producer activity and temporary shut-ins, while the decrease in the Permian was primarily due to the sale of the Delaware crude system in the fourth quarter of 2019.

Operating expenses were lower due to cost reduction measures that resulted in decreases in compensation and benefits, contract labor and chemicals, despite the addition of the Peregrine and Gateway processing facilities in the Permian.

Nine Months Ended September 30, 2020 Compared to Nine Months Ended September 30, 2019

Gathering and Processing segment gross margin contributions, attributable to higher inlet volumes and fee-based margin in the Permian region and Badlands and higher realized hedge gains, were offset by lower commodity prices and lower Central region volumes. In the Permian, inlet volumes and NGL production increased due to production from new wells and the addition of the Hopson, Pembrook and Falcon plants in 2019 and the Peregrine and Gateway plants in 2020. Lower volumes in the Central region were attributable to temporary shut-ins and reduced producer activity. In the Badlands, natural gas purchased volumes and NGL production increased due to production from new wells and the incremental processing capacity available with the commencement of operations at the Little Missouri 4 Plant in the third quarter of 2019. In the Coastal region, volumes were lower due to continued low producer activity and the effects of multiple Gulf Coast hurricanes in the third quarter of 2020, which necessitated temporary shutdowns of certain facilities in Louisiana. Total crude oil volumes decreased in the Badlands due to reduced producer activity and temporary shut-ins, while the decrease in the Permian was primarily due to the sale of the Delaware crude system in the fourth quarter of 2019.

Operating expenses were lower due to cost reduction measures that resulted in decreases in contract labor, chemicals and compression rentals and lower ad valorem taxes, despite the addition of the Peregrine and Gateway processing facilities in the Permian.

Three Months Ended September 30, ~~2017~~2020 Compared to Three Months Ended September 30, ~~2016~~2019

The increase in Logistics and ~~Marketing~~Transportation segment gross margin ~~decreased~~was primarily due to ~~lower~~higher NGL transportation and fractionation margin and higher LPG export margin, partially offset by lower marketing margin. NGL transportation and fractionation margin increased due to higher volumes delivered on Grand Prix, which began full service into Mont Belvieu during the third quarter of 2019, and higher fractionation ~~margin, higher marketing gains,~~volumes as a result of the commencement of operations of Train 7 in the first quarter of 2020 and ~~higher terminaling and storage throughput.~~Train 8 late in the third quarter of 2020. LPG export margin increased due to higher volumes driven by expansion of our LPG export capabilities. Marketing margin decreased primarily due to lower fees. LPG export volumes decreased due to the deferral to the fourth quarter of 2017 of 12.5 MBbl/d of export volumes due to the temporary closure of the Houston Ship Channel resulting from Hurricane Harvey. Fractionationless optimization margin increased due to higher system product gains, higher supply volume despite the deferral to the fourth quarter of 2017 of 29.3 MBbl/d of supply volumes due to the temporary operational issues related to Hurricane Harvey, and higher fees. Fractionation gross margin was partially impacted by the variable effects of lower fuel and power that are largely reflectedrealized in ~~operating expenses (see footnote (2) above).~~our marketing businesses.

Operating expenses ~~increased primarily due to higher labor, higher repairs~~were flat, despite the operations of a number of system expansions, including Grand Prix, additional incremental fractionation capacity and ~~maintenance, partially offset by lower~~expansion of our LPG export capabilities. Lower fuel and power costs and cost reduction measures that ~~is largely passed through.~~resulted in lower compensation and maintenance were offset by increased taxes primarily attributable to Grand Prix and the inclusion of our share of operating expenses associated with GCF.

Nine Months Ended September 30, ~~2017~~2020 Compared to Nine Months Ended September 30, ~~2016~~2019

The increase in Logistics and Transportation segment gross margin results for the nine months ended September 30, 2017 were impacted by the same factors as discussed above for the three months ended September 30, 2017, with the exception of fuel and power, which were higher. Additional factors were lower commercial transportation margin and lower domestic marketing margin. Commercial transportation margin decreased primarily due to lower barge activity. Domestic marketing margin decreased primarily due to lower terminal margins.

~~Operating expenses increased~~was primarily due to higher ~~fuel~~NGL transportation and ~~power which is largely passed through, higher labor associated with Train 5,~~fractionation margin and higher ~~maintenance associated with unusual one-time events~~LPG export margin, partially offset by lower marketing margin. NGL transportation and fractionation margin increased due to higher volumes delivered on Grand Prix, which began full service into Mont Belvieu during the third quarter of 2019, and higher fractionation volumes as a result of the commencement of operations of Train 6 in the second quarter of 2019, Train 7 in the first quarter of ~~2017.~~2020 and Train 8 late in the third quarter of 2020. LPG export margin increased due to higher volumes driven by expansion of our LPG export capabilities. Marketing margin decreased due to less optimization margin realized in our marketing businesses.

Operating expenses were higher primarily due to theinclusion of our share of operating expenses associated with GCF, increased costs attributable to our fractionation and LPG export expansions, higher taxes primarily attributable to Grand Prix and to additional incremental fractionation capacity, and higher maintenance primarily attributable to Grand Prix, partially offset by lower fuel and power costs.

	Three Months Ended September 30,								Nine Months Ended September 30,							Three Months Ended September 30,							Nine Months Ended September 30,
	2017			2016		2017 vs. 2016			2017		2016		2017 vs. 2016			2020		2019			2020 vs. 2019		2020		2019			2020 vs. 2019
	(In millions)															(In millions)							(In millions)
Gross margin	$	(1.0	)	$	11.2	$	(12.2	)	$	3.9	$	56.9	$	(53.0	)	$	88.6	$	(101.2	)	$	189.8	$	215.9	$	(101.1	)	$	317.0
Operating margin	$	(1.0	)	$	11.2	$	(12.2	)	$	3.9	$	56.9	$	(53.0	)	$	88.6	$	(101.2	)	$	189.8	$	215.9	$	(101.1	)	$	317.0

Other contains the results ~~(including any hedge ineffectiveness)~~ of commodity derivative ~~activities related to Gathering and Processing hedges of equity volumes that are included in operating margin and~~activity mark-to-market ~~gain/~~gains/losses related to derivative contracts that were not designated as cash flow hedges. ~~The primary purpose of our commodity risk management activities is to mitigate a portion of~~

~~the impact of commodity prices on our operating cash flow.~~ We have entered into derivative instruments to hedge the commodity price associated with a portion of our ~~expected~~future commodity purchases and sales and natural gas ~~NGL~~transportation basis risk within our Logistics and ~~condensate equity volumes in our Gathering and Processing Operations that result from percent of proceeds/liquids processing arrangements. Because we are essentially forward-selling a portion~~Transportation segment. See further details of our ~~future plant equity volumes, these hedge positions will move favorably~~risk management program in ~~periods of falling commodity prices~~“Item 3. – Quantitative and ~~unfavorably in periods of rising commodity prices.~~Qualitative Disclosures About Market Risk.”

~~The following table provides a breakdown of the change in Other operating margin:~~

Three Months Ended September 30, 2017

Three Months Ended September 30, 2016

(In millions, except volumetric data and price amounts)

Volume
Settled

Price
Spread
(1)

Gain
(Loss)

Volume
Settled

Price
Spread
(1)

Gain
(Loss)

2017 vs. 2016

Natural gas (BBtu)

17.3

$
0.23

$
4.0

13.8

$
0.37

$
5.1

$
(1.1
)
NGL (MMgal)

74.8

(0.09
)

(6.7
)

(7.2
)

(0.25
)

1.8

(8.5
)
Crude oil (MBbl)

0.4

6.29

2.3

0.3

14.40

4.7

(2.4
)
Non-hedge accounting (2)

(0.6
)

(0.1
)

(0.5
)
Ineffectiveness (3)

-

(0.3
)

0.3

$
(1.0
)

$
11.2

$
(12.2
)

Nine Months Ended September 30, 2017

Nine Months Ended September 30, 2016

(In millions, except volumetric data and price amounts)

Volume
Settled

Price
Spread
(1)

Gain
(Loss)

Volume
Settled

Price
Spread
(1)

Gain
(Loss)

2017 vs. 2016

Natural gas (BBtu)

43.3

$
0.15

$
6.6

34.0

$
0.94

$
31.9

$
(25.3
)
NGL (MMgal)

177.5

(0.04
)

(7.7
)

20.2

0.34

6.9

(14.6
)
Crude oil (MBbl)

0.9

6.29

5.8

0.8

20.02

16.2

(10.4
)
Non-hedge accounting (2)

(0.9
)

2.5

(3.4
)
Ineffectiveness (3)

0.1

(0.6
)

0.7

$
3.9

$
56.9

$
(53.0
)

As part of the Atlas mergers, outstanding TPL derivative contracts with a fair value of $102.1 million as of February 27, 2015 (the “acquisition date”), were novated to us and included in the acquisition date fair value of assets acquired. We received derivative settlements of $1.4 million and $6.3 million for the three and nine months ended September 30, 2017 and $5.8 million and $20.9 million for the three and nine months ended September 30, 2016, related to these novated contracts. From the acquisition date through September 30, 2017, we have received total derivative settlements of $100.9 million. ~~The remainder of the novated contracts will settle by the end of 2017.~~ ~~These settlements were reflected as a reduction of the acquisition date fair value of the TPL derivative assets acquired and had no effect on results of operations.~~

As of September 30, ~~2017,~~2020, we had ~~$103.9~~$248.0 million of “Cash and cash equivalents,” on our Consolidated Balance Sheets. We believe our cash position, our cash flows from operating activities and remaining borrowing capacity on our credit ~~facilities~~facility (discussed below in “Short-term Liquidity”)~~, and our cash flows from operating activities~~ are adequate to allow us to manage our day-to-day cash requirements and anticipated obligations as discussed further below.

Our ability to finance our operations, including funding capital expenditures and acquisitions, meeting our indebtedness obligations, refinancing or repaying our indebtedness, and meeting our collateral requirements, will depend on our ability to generate cash in the future. Our ability to generate cash is subject to a number of factors, some of which are beyond our control. These include commodity prices ~~weather~~ and ongoing efforts to manage operating costs and maintenance capital expenditures, as well as general economic, financial, competitive, legislative, regulatory and other factors. For additional discussion on recent factors impacting our liquidity and capital resources, please see “Recent Developments – Response to Current Market Conditions.”

Our main sources of liquidity and capital resources are internally generated cash flows from operations, contributions from TRC that are funded through TRC’s access to debt and equity markets, borrowings under the TRP Revolver and the Securitization Facility, and access to debt markets. We supplement these sources of liquidity with joint venture arrangements and proceeds from asset sales. For companies involved in hydrocarbon production, transportation and other oil and gas related services, the capital markets have experienced and may continue to experience volatility. Our exposure to adverse credit conditions includes our credit facility, cash investments, hedging abilities, customer performance risks and counterparty performance risks.

		October 31, 2017				November 2, 2020
		(In millions)				(In millions)
Cash on hand	Cash on hand	$	196.3		Cash on hand	$	252.3
Total availability under the TRP Revolver	Total availability under the TRP Revolver		1,600.0		Total availability under the TRP Revolver		2,200.0
Total availability under the Securitization Facility	Total availability under the Securitization Facility		350.0		Total availability under the Securitization Facility		250.0
			2,146.3				2,702.3

Less:	Outstanding borrowings under the TRP Revolver		—		Outstanding borrowings under the TRP Revolver		(600.0	)
	Outstanding borrowings under the Securitization Facility		(270.0	)	Outstanding borrowings under the Securitization Facility		(250.0	)
	Outstanding letters of credit under the TRP Revolver		(24.6	)	Outstanding letters of credit under the TRP Revolver		(37.5	)
	Total liquidity	$	1,851.7		Total liquidity	$	1,814.8

Other potential capital resources associated with our existing arrangements include:

A portion of our capital resources are allocated to letters of credit to satisfy certain counterparty credit requirements. These letters of credit reflect our non-investment grade status, as assigned to us by Moody’s and S&P. They also reflect certain counterparties’ views of our financial condition and ability to satisfy our performance obligations, as well as commodity prices and other factors.

Working capital is the amount by which current assets exceed current liabilities. On a consolidated basis, at the end of any given month, accounts receivable and payable ~~that are~~ tied to commodity sales and purchases are relatively balanced, with receivables from ~~NGL and natural gas~~ customers being offset by plant settlements payable to producers. The factors that typically cause overall variability in our reported total working capital are: ~~(1)~~(i) our cash position; ~~(2)~~(ii) liquids inventory levels and valuation, which we closely manage; ~~(3)~~(iii) changes in payables and accruals related to major growth capital projects; (iv) changes in the fair value of the current portion of derivative contracts; (v) monthly swings in borrowings under the Securitization Facility; and ~~(4)~~(vi) major structural changes in our asset base or business operations, such as acquisitions or divestitures and certain organic growth capital projects.

~~Our working~~Working capital ~~exclusive~~as of ~~current debt obligations,~~ September 30, 2020 increased ~~$34.7~~$249.7 million ~~from~~compared to December 31, ~~2016 to September 30, 2017.~~ 2019. The ~~major items contributing to this~~ increase ~~were the increase in inventory due~~was primarily attributable to higher ~~prices~~inventory balances, lower current maturities of debt from payments on our Securitization Facility, and ~~volumes, additional collateral posted with our futures broker due to an increase in commodity prices,~~lower payables for capital expenditures and ~~greater cash on hand. This increase was~~product purchases, partially offset by an increase in capital expenditure accruals driven primarily by the Permian activities, and a decrease in our net risk management working capital position due to changes in the forward prices of commodities. The increase of $253.4 million in current debt obligations was mainly due to the reclassification of the remaining 5% Notes due 2018 to short-term. These notes were redeemed on October 30, 2017.lower receivables resulting from lower commodity prices.

Based on our anticipated levels of operations and absent any disruptive events, we believe that internally generated cash flow, contributions from TRC, borrowings available under the TRP Revolver and the Securitization Facility and proceeds from debt offerings, as well as joint ventures and/or asset sales, should provide sufficient resources to finance our operations, capital expenditures, long-term debt obligations, collateral requirements and ~~quarterly~~ cash distributions to Targa for at least the next twelve months.

In February 2018, we formed three development joint ventures (“DevCo JVs”) with investment vehicles affiliated with Stonepeak Infrastructure Partners (“Stonepeak”), which committed a maximum of ~~long-term debt obligations~~approximately $960 million of capital to the DevCo JVs.

As of September 30, 2020, total contributions from Stonepeak to the DevCo JVs were $911.4 million. As of September 30, 2020, total contributions from funds managed by Blackstone Energy Partners (“Blackstone”) to the Grand Prix Joint Venture were $341.3 million. These contributions from Stonepeak and ~~preferred units.~~Blackstone are included in noncontrolling interests.

From time to time, we issue long-term debt securities, which we refer to as senior notes. Our senior notes issued to date, generally have similar terms other than interest rates, maturity dates and redemption premiums. ~~All of our fixed rate senior notes provide that the notes may be redeemed at any time at a price equal to 100% plus accrued interest to the redemption date, and in some cases, a make-whole premium.~~ As of September 30, ~~2017~~2020, and December 31, ~~2016,~~2019, the aggregate principal amount outstanding of our senior notes and other various long-term debt obligations, ~~(excluding current maturities)~~including unamortized premiums, debt issuance costs and non-current liabilities of finance leases, was ~~$3,957.6~~$7,217.2 million and ~~$4,206.8~~$7,005.2 million, respectively.~~In October 2017, we issued $750.0 million aggregate principal amount of 5% Senior Notes due 2028, with net proceeds of $744.4 million after costs,~~ ~~and redeemed our outstanding 5% Senior Notes due 2018 at face value plus accrued interest through the redemption date.~~

The majority of our ~~long-term~~ debt is fixed rate borrowings; however, we have some exposure to the risk of changes in interest rates, primarily as a result of the variable rate borrowings under the TRP ~~Revolver.~~Revolver and the Securitization Facility. We may enter into interest rate hedges with the intent to mitigate the impact of changes in interest rates on cash flows. As of September 30, ~~2017,~~2020, we dodid not have any interest rate hedges.

In 2019, we closed on the sale of a 45% interest in Targa Badlands to GSO Capital Partners and Blackstone Tactical Opportunities (collectively, “GSO”) for $1.6 billion in cash. Growth capital of Targa Badlands after the sale is funded on a pro rata ownership basis. Targa Badlands pays a minimum quarterly distribution (“MQD”) to GSO and Targa, with GSO having a priority right on such MQDs. Additionally, GSO’s capital contributions would have a liquidation preference upon a sale of Targa Badlands. Targa Badlands is a discrete entity and the assets and credit of Targa Badlands are not available to satisfy the debts and other obligations of Targa or its other subsidiaries. As of September 30, 2020, the contributions from GSO were $74.0 million.

On November 2, 2020, we redeemed the $559.6 million remaining balance of our 5 ¼% Senior Notes due 2023.

In the third quarter of 2020, we issued $1.0 billion of 4⅞% Senior Notes due 2031, resulting in net proceeds of $991.0 million. A portion of the net proceeds from the issuance were used to fund the Tender Offer and redemption payments for our 6¾% Notes, with the remainder used for repayment of borrowings under the TRP Revolver.

We accepted for purchase all the notes that were validly tendered as of the early tender date, which totaled $262.1 million and redeemed the remaining aggregate principal amount of the 6¾% Notes, which totaled $318.0 million. We recorded a loss due to debt extinguishment of $13.7 million comprised of $11.1 million premiums paid and a write-off of $2.6 million of debt issuance costs.

Additionally, during the first half of 2020, we repurchased a portion of the outstanding senior notes on the open market, paying $239.8 million plus accrued interest to repurchase $303.3 million of the notes. The repurchases resulted in a $61.1 million net gain, which included the write-off of $2.4 million in related debt issuance costs. We may retire or purchase various series of our outstanding debt through cash purchases and/or exchanges for other debt, in open market purchases, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.

To date, ~~we do not believe~~ our debt balances have not adversely affected our operations, ability to grow or ability to repay or refinance indebtedness. For additional information about our debt-related transactions, see Note 105 - Debt Obligations to our consolidated financial statements. For information about our interest rate risk, see “Item 3. Quantitative and Qualitative Disclosures About Market Risk—Interest Rate Risk.”

In October 2015, we completed an offering of 5,000,000 Preferred Units at a price of $25.00 per unit. We received net proceeds after costs of approximately $121.1 million. The Preferred Units are listed on the NYSE under the symbol “NGLS PRA.” Distributions on our 5,000,000 Preferred Units are cumulative from the date of original issue in October 2015 and are payable monthly in arrears on the 15th day of each month of each year, when, as and if declared by the board of directors of our general partner. Distributions on our Preferred Units are payable out of amounts legally available at a rate equal to 9.0% per annum.

On and after November 1, 2020, distributions on our Preferred Units will accumulate at an annual floating rate equal to the one-month LIBOR plus a spread of 7.71%. At any time on or after November 1, 2020, we may redeem the Preferred Units, in whole or in part, from any source of funds legally available for such purpose, by paying $25.00 per unit plus an amount equal to all accumulated and unpaid distributions thereon to the date of redemption, whether or not declared. In addition, we (or a third party with our prior written consent) may redeem the Preferred Units following certain changes of control, as described in our Partnership Agreement. If we do not (or a third party with our prior written consent does not) exercise this option, then the ~~holders of the~~ Preferred ~~Units (“Preferred Unitholders”)~~Unitholders have the option to convert the Preferred Units into a number of common units per Preferred Unit as set forth in our Partnership Agreement.

As of September 30, ~~2017,~~2020, we were in compliance with the covenants contained in our various debt agreements.

The ~~Consolidated Statements~~primary drivers of ~~Cash Flows included in our historical consolidated financial statements employs the traditional indirect method of presenting~~ cash flows from operating ~~activities. Under~~activities are (i) the ~~indirect method, net~~collection of cash from customers from the sale of NGLs, natural gas and other petroleum commodities, as well as fees for processing, gathering, export, fractionation, terminaling, storage and transportation, (ii) the payment of amounts related to the purchase of NGLs, natural gas and crude oil (iii) changes in payables and accruals related to major growth capital projects, and (iv) the payment of other expenses, primarily field operating costs, general and administrative expense and interest expense. In addition, we use derivative instruments to manage our exposure to commodity price risk. Changes in the prices of the commodities we hedge impact our derivative settlements as well as our margin deposit requirements on unsettled futures contracts.

Net cash provided by ~~operating activities is derived by adjusting our net income for non-cash items related to operating activities. An alternative GAAP presentation employs the direct method~~operations increased in ~~which the actual cash receipts and outlays comprising cash flow are presented.~~

~~The following table displays our operating cash flows using the direct method as a supplement to the presentation in our consolidated financial statements:~~

~~Higher commodity prices were the primary contributor to increased cash collections and payments for product purchases in 2017~~2020 compared to 2016. Cash received from derivative settlements was lower as commodity price spreads between the prices paid to counterparties and the fixed prices we received on those derivative contracts were lower in 2017 in comparison to 2016. Interest payments are lower this year largely due to lower average outstanding debt balances, offset by the timing of payments of interest on two new series of notes we issued in 2016. ~~Cash payments for operating expenses and general and administrative expenses increased~~2019 primarily due to higher ~~compensation~~operating margin and ~~benefits, contractor and other professional services, coupled with~~an increase in cash distributions received from unconsolidated affiliates, partially offset by an increase in interest payments as a result of higher ~~utilities and higher maintenance.~~ ~~Other cash payments in 2017 were higher mainly due to transaction expenses associated with the~~ ~~Permian Acquisition in 2017.~~average borrowings.

Nine Months Ended September 30,	Nine Months Ended September 30,								Nine Months Ended September 30,
2017			2016			2017 vs. 2016
2020									2020		2019			2020 vs. 2019
(In millions)	(In millions)								(In millions)
$	(1,457.5	)	$	(422.0	)	$	(1,035.5	)	(654.0	)	$	(2,619.7	)	$	1,965.7

Cash used in investing activities ~~increased~~decreased in ~~2017~~2020 compared to ~~2016,~~2019, primarily due to lower outlays for property, plant and equipment of $1,630.7 million, resulting from the completion of construction of Grand Prix, Train 6, Train 7, and additional processing plants and associated infrastructure in the Permian Basin in 2019 and early 2020. The change is also attributable to proceeds of $134.1 million received from the sale of our Delaware crude system and a $241.5 million decrease in our contributions to unconsolidated affiliates primarily due to the ~~$570.8 million outlay for the cash portion~~completion of the Permian Acquisition consideration. Capital expenditures increased $441.6 million during 2017 reflecting the spending for major growth projects during 2017 and the acquisition of the Flag City Plant.GCX Pipeline in 2019.

							Nine Months Ended September 30,
	Nine Months Ended September 30,						2020			2019
	2017			2016			(In millions)
Source of Financing Activities, net	(In millions)
Distributions							$	(346.8	)	$	(921.5	)
Contributions from (distributions to) noncontrolling interests								(277.3	)		419.8
Debt, including financing costs								130.1			823.7
Contributions from TRC and General Partner	$	1,620.0		$	1,191.0			50.0			200.0
Distributions		(633.1	)		(542.9	)
Debt, including financing costs		(4.6	)		(808.6	)
Equity offerings, net of financing costs		-			(7.5	)
Sale of ownership interests in subsidiaries								—			1,619.7
Payment of contingent consideration								—			(317.1	)
Other		47.9			15.8			—			(10.7	)
Net cash provided by (used in) financing activities	$	1,030.2		$	(152.2	)
Net cash provided by financing activities							$	(444.0	)	$	1,813.9

In ~~2017,~~2020, net cash used in financing activities is primarily due to distributions to TRC, and net distributions to noncontrolling interests, partially offset by a net increase of debt outstanding and contributions from TRC and General Partner. Our distributions to noncontrolling interests are higher than our contributions from noncontrolling interests in 2020, primarily due to completion of major growth capital projects in 2019. Our debt outstanding increased primarily due to the issuance of the 4⅞% Senior Notes due 2031 that resulted in cash proceeds of $991.0 million, partially offset by repurchasing a portion of our outstanding senior notes through open market purchases and the Tender Offer and redemption payments for the 6¾% Notes for a total of $831.0 million.

In 2019, we realized a net source of cash from financing activities primarily due to ~~contributions from TRC~~the sale of ownership interests in Targa Badlands and ~~General Partner, partially offset by a~~Train 7, net ~~reduction of debt borrowings and payments of distributions to TRC. We reduced net debt borrowings through~~

~~repayments of the TRP Revolver and redemption of our~~ ~~6⅜%~~ ~~Senior Notes. In September 2017, we sold a 25% interest in the Grand Prix Joint Venture and received a total of $75.0 million in contributions from Blackstone.~~

~~In 2016, we incurred a net use of cash from financing activities primarily due to a net reduction~~increase of debt outstanding and ~~payment~~net contributions from noncontrolling interests. The result was partially offset by payments of distributions, ~~to TRC,~~as well as the final contingent consideration payment associated with our 2017 acquisition of gas gathering and processing and crude oil gathering assets in the Permian Basin. The issuance of 6½% Senior Notes due 2027 and 6⅞% Senior Notes due January 2029, partially offset by the redemption of 4⅛% Senior Notes due November 2019 contributed to the net increase of debt outstanding. The contributions from ~~TRC~~noncontrolling interests were primarily from Stonepeak and ~~our general partner. With the contributions from TRC, we repurchased a portion of our senior notes through open market repurchases generally at a discount~~Blackstone to ~~par values and repaid a portion of the outstanding borrowings under the TRP Revolver.~~fund growth capital projects.

TRC is entitled to receive all available Partnership distributions after ~~payment~~payments of preferred distributions each quarter. We have discretion under the Third A&R Partnership Agreement, as to whether to distribute all available cash for any period. See Note 1 – Organization and Operations of the “Consolidated Financial Statements” included in this quarterly report.

The following table details the distributions declared and/or paid by us during the ~~three and~~ nine months ended September 30, ~~2017.~~2020:

Distributions on our Preferred Units are declared and paid monthly. As of September 30, ~~2017,~~2020, we have 5,000,000 Preferred Units outstanding. For the three and nine months ended September 30, ~~2017,~~2020, $2.8 million and $8.4 million of distributions were paid. We have accrued distributions to Series A Preferred Unitholders of $0.9 million for September, which were paid subsequently on October ~~16, 2017.~~15, 2020.

In October ~~2017,~~2020, the board of directors of our general partner declared a cash distribution of $0.1875 per Preferred Unit. This distribution will be paid on November ~~15, 2017.~~

Our capital requirements relate to capital expenditures, which are classified as expansion expenditures (including business acquisitions), and maintenance expenditures. Expansion capital expenditures improve the service capability of the existing assets, extend asset useful lives, increase capacities from existing levels, add capabilities, reduce costs or enhance revenues, and fund acquisitions of businesses or assets. Maintenance capital expenditures are those expenditures that are necessary to maintain the service capability of our existing assets, including the replacement of system components and equipment, which are worn, obsolete or completing their useful life and expenditures to remain in compliance with environmental laws and regulations.16, 2020.

~~We currently estimate that we will invest approximately $1,320.0 million in net growth capital expenditures (exclusive of~~

The following table details cash outlays for ~~business acquisitions) for announced~~capital projects in 2017. Given our objective of growth through expansions of existing assets, other internal growth projects, and acquisitions, we anticipate that over time that we will invest significant amounts of capital to grow and acquire assets. Future expansion capital expenditures may vary significantly based on investment opportunities. We continue to expect that 2017 net maintenance capital expenditures will be approximately $110.0 million.

~~Our expansion capital expenditures increased~~ for the nine months ended September 30, ~~2017~~2020 and 2019:

We currently estimate that in 2020 we will invest approximately $700 million in growth capital expenditures, net of noncontrolling interests, and net contributions to investments in unconsolidated affiliates for announced projects. We expect that 2020 maintenance capital expenditures, net of noncontrolling interests, will be approximately $110 million.

Total growth capital expenditures were lower for the nine months ended September 30, 2020 as compared to the nine months ended September 30, ~~2016,~~2019, primarily due to lower spending ~~related to~~on growth capital investments, as a significant portion of our major projects began full service in 2019, including Grand Prix, Train 6, and additional processing plants and associated infrastructure in the Permian Basin, the Grand Prix NGL pipeline and the Channelview Splitter, as well as the acquisition of the Flag City. The increase was partially offset by the impact of the substantial completion of the CBF Train 5 project in the second quarter of 2016. OurBasin. Total maintenance capital expenditures ~~increased~~were lower for ~~2017~~the nine months ended September 30, 2020 as compared to ~~2016,~~the nine months ended September 30, 2019, primarily due to ~~higher volumes processed on our system.~~ timing of maintenance projects.

As of September 30, ~~2017,~~2020, there were ~~$38.3~~$44.9 million in surety bonds outstanding related to various performance obligations. These are in place to support various performance obligations as required by (i) statutes within the regulatory jurisdictions where we operate and (ii) counterparty support. Obligations under these surety bonds are not normally called, as we typically comply with the underlying performance requirement.

Our principal market risks are our exposure to changes in commodity prices, particularly to the prices of natural gas, NGLs and crude oil, changes in interest rates, as well as nonperformance by our customers.

We evaluate counterparty risks related to our commodity derivative contracts and trade credit. We have all our commodity derivatives with major financial institutions or major ~~oil~~energy companies. Should any of these financial counterparties not perform, we may not realize the benefit of some of our hedges under lower commodity prices, which could have a material adverse effect on our results of operations. We sell our natural gas, NGLs and condensate to a variety of purchasers. Non-performance by a trade creditor could result in losses.

Crude oil, NGL and natural gas prices are also volatile. In an effort to reduce the variability of our cash flows, we have entered into derivative instruments to hedge the commodity price associated with a portion of our expected natural gas, ~~equity volumes,~~ NGL ~~equity volumes~~ and condensate equity volumes ~~and~~, future commodity purchases and sales, and transportation basis risk through ~~2020.~~2025. Market conditions may also impact our ability to enter into future commodity derivative contracts.

A ~~significant~~ portion of our revenues are derived from percent-of-proceeds contracts under which we receive a portion of the proceeds from the sale of ~~natural gas and/or NGLs~~commodities as payment for services. The prices of natural gas, NGLs and ~~NGLs~~crude oil are subject to fluctuations in response to changes in supply, demand, market uncertainty and a variety of additional factors beyond our control. We monitor these risks and enter into hedging transactions designed to mitigate the impact of commodity price fluctuations on our business. Cash flows from a derivative instrument designated as a hedge are classified in the same category as the cash flows from the item being hedged.

The primary purpose of our commodity risk management activities is to hedge some of the exposure to commodity price risk and reduce fluctuations in our operating cash flow due to fluctuations in commodity prices. In an effort to reduce the variability of our cash flows, as of September 30, ~~2017,~~2020, we have hedged the commodity price associated with a portion of our expected (i) natural gas, NGL, and condensate equity volumes in our Gathering and Processing operations that result from our percent-of-proceeds processing arrangements, ~~and~~ (ii) future commodity purchases and sales in our Logistics and ~~Marketing~~Transportation segment and (iii) natural gas transportation basis risk in our Logistics and Transportation segment by entering into derivative instruments. We hedge a higher percentage of our expected equity volumes in the current year compared to future years, for which we hedge incrementally lower percentages of expected equity volumes. With swaps, we typically receive an agreed fixed price for a specified notional quantity of natural gas or NGLs and we pay the hedge counterparty a floating price for that same quantity based upon published index prices. Since we receive from our customers substantially the same floating index price from the sale of the underlying physical commodity, these transactions are designed to effectively lock-in the agreed fixed price in advance for the

volumes hedged. In order to avoid having a greater volume hedged than our actual equity volumes, we typically limit our use of swaps to hedge the prices of less than our expected ~~natural gas and NGL~~ equity volumes. We utilize purchased puts (or floors) and calls (or caps) to hedge additional expected equity commodity volumes without creating volumetric risk. We may buy calls in connection with swap positions to create a price floor with upside. We intend to continue to manage our exposure to commodity prices in the future by entering into derivative transactions using swaps, collars, purchased puts (or floors), futures or other derivative instruments as market conditions permit.

When entering into new hedges, we intend to generally match the NGL product composition and the NGL and natural gas delivery points to those of our physical equity volumes. The NGL hedges cover specific NGL products based upon the expected equity NGL composition. We believe this strategy avoids uncorrelated risks resulting from employing hedges on crude oil or other petroleum products as “proxy” hedges of NGL prices. The fair value of our natural gas and NGL ~~hedges’ fair values~~hedges are based on published index prices for delivery at various locations, which closely approximate the actual natural gas and NGL delivery points. A portion of our condensate sales are hedged using crude oil hedges that are based on the NYMEX futures contracts for West Texas Intermediate light, sweet crude.

A majority of these commodity price ~~hedging transactions~~hedges are ~~typically~~ documented pursuant to a standard International Swap Dealers Association form with customized credit and legal terms. The principal counterparties (or, if applicable, their guarantors) have investment grade credit ratings. Our payment obligations in connection with substantially all of these hedging transactions and any additional credit exposure due to a rise in commodity prices relative to the fixed prices set forth in the hedges are secured by a first priority lien in the collateral securing our senior secured indebtedness that ranks equal in right of payment with liens granted in favor of our senior secured lenders. Absent federal regulations resulting from the Dodd-Frank Act, and as long as this first priority lien is in effect, we expect to have no obligation to post cash, letters of credit or other additional collateral to secure these hedges at any time, even if a counterparty’s exposure to our credit increases over the term of the hedge as a result of higher commodity prices or because there has been a change in our creditworthiness. A purchased put (or floor) transaction does not expose our counterparties to credit risk, as we have no obligation to make future payments beyond the premium paid to enter into the transaction; however, we are exposed to the risk of default by the counterparty, which is the risk that the counterparty will not honor its obligation under the put transaction.

We also enter into commodity price hedging transactions using futures contracts on futures exchanges. Exchange traded futures are subject to exchange margin requirements, so we may have to increase our cash deposit due to a rise in natural gas, ~~and~~ NGL or crude oil prices. Unlike bilateral hedges, we are not subject to counterparty credit risks when using futures on futures exchanges.

Our operating revenues increased (decreased) by net hedge adjustments on commodity derivative contracts of $(3.6) million and $7.5 million, during the three months ended September 30, 2017 and 2016, and $(4.9) million and $46.4 million, during the nine months ended September 30, 2017 and 2016, as a result of transactions accounted for as derivatives. We account for derivatives designated as hedges that mitigate commodity price risk as cash flow hedges. Changes in fair value are deferred in other comprehensive income until the underlying hedged transactions settle. We also enter into derivative instruments to help manage other short-term commodity-related business risks. We have not designated these derivatives as hedges and record changes in fair value and cash settlements to revenues.

Our risk management position has moved from a net liability position of $53.3 million at December 31, 2016 to a net liability position of $63.4 million at September 30, 2017. The fixed prices we currently expect to receive on derivative contracts are below the aggregate forward prices for commodities related to those contracts, creating this net liability position.

~~As of September 30, 2017, we had the following derivative instruments that will settle during the years shown below:~~

Instrument

Price

Type
Index
$/MMBtu

MMBtu/d

Fair Value

2017

2018

2019

2020

(In millions)

Gathering & Processing

Swap
IF-Waha

2.8740

103,600

-

-

-

$
2.7

Swap
IF-Waha

2.6470

-

93,600

-

-

4.0

Swap
IF-Waha

2.6327

-

-

65,383

-

6.2

103,600

93,600

65,383

-

Swap
IF-PB

2.6602

40,900

-

-

-

0.5

Swap
IF-PB

2.4802

-

45,900

-

-

0.2

Swap
IF-PB

2.3700

-

-

35,000

-

0.9

40,900

45,900

35,000

-

Swap
IF-PEPL

2.6835

16,000

-

-

-

0.1

Swap
IF-PEPL

2.6835

-

16,000

-

-

0.6

Swap
IF-PEPL

2.6835

-

-

16,000

-

1.5

16,000

16,000

16,000

-

Swap
NG-NYMEX

3.9900

9,783

-

-

-

0.8

Put Price

Call Price

Collar
IF-Waha

3.0000

3.6700

7,500

-

-

-

0.3

Collar
IF-Waha

3.2500

4.2000

-

1,849

-

-

0.3

7,500

1,849

-

-

Put Price

Call Price

Collar
IF-PB

2.8000

3.5000

15,400

-

-

-

0.4

Collar
IF-PB

3.0000

3.6500

-

7,637

-

-

1.5

15,400

7,637

-

-

Basis Swap
EP-PERMIAN

(0.1444
)

4,891

-

-

-

0.2

Basis Swap
PEPL

(0.3308
)

4,891

-

-

-

0.0

Gathering & Processing total

202,965

164,986

116,383

0

$
20.2

Other (1)

Swap
NG-NYMEX

(3.1680
)

(229
)

(173
)

(247
)

-

$
(0.0
)
Swap
IF-Waha

3.0647

(9,707
)

(4,227
)

-

-

(0.5
)
Basis Swap
Various
Various

82,418

15,726

12,500

10,445

(1.3
)
Future
Various

3.2640

-

1,103

-

-

(0.0
)
Other total

72,482

12,429

12,253

10,445

$
(1.8
)

$
18.4

Instrument

Price

Type
Index
$/gal

Bbl/d

Fair Value

2017

2018

2019

(In millions)

Gathering & Processing

Swap
C2-OPIS-MB

0.2778

6,030

-

-

$
0.0

Swap
C2-OPIS-MB

0.2816

-

4,118

-

(0.4
)
Swap
C2-OPIS-MB

0.2951

-

-

3,460

(1.0
)
Total

6,030

4,118

3,460

Swap
C3-OPIS-MB

0.6598

10,382

-

-

(9.7
)
Swap
C3-OPIS-MB

0.6274

-

5,510

-

(8.5
)
Swap
C3-OPIS-MB

0.5530

-

-

2,650

(3.8
)
Total

10,382

5,510

2,650

Swap
IC4-OPIS-MB

0.8570

1,400

-

-

(1.1
)
Swap
IC4-OPIS-MB

0.8053

-

560

-

(0.6
)
Swap
IC4-OPIS-MB

0.7133

-

-

170

(0.2
)
Total

1,400

560

170

Swap
NC4-OPIS-MB

0.8538

3,930

-

-

(2.9
)
Swap
NC4-OPIS-MB

0.7969

-

1,530

-

(1.4
)
Swap
NC4-OPIS-MB

0.6989

-

-

460

(0.6
)
Total

3,930

1,530

460

Swap
C5-OPIS-MB

1.0997

1,690

-

-

(0.7
)
Swap
C5-OPIS-MB

1.0703

-

1,140

-

(2.1
)
Swap
C5-OPIS-MB

1.0783

-

-

659

(0.9
)
Total

1,690

1,140

659

Put Price

Call Price

Collar
C2-OPIS-MB

0.240

0.290

410

-

-

(0.0
)

Put Price

Call Price

Collar
C3-OPIS-MB

0.570

0.68625

380

-

-

(0.3
)
Collar
C3-OPIS-MB

0.530

0.65000

-

900

-

(1.7
)
Total

380

900

-

Put Price

Call Price

Collar
IC4-OPIS-MB

0.650

0.840

-

110

-

(0.2
)
Collar
IC4-OPIS-MB

0.640

0.800

-

-

110

(0.2
)
Total

-

110

110

Put Price

Call Price

Collar
NC4-OPIS-MB

0.650

0.800

-

300

-

(0.6
)
Collar
NC4-OPIS-MB

0.640

0.760

-

-

300

(0.4
)
Total

-

300

300

Put Price

Call Price

Collar
C5-OPIS-MB

1.210

1.415

130

-

-

0.0

Collar
C5-OPIS-MB

1.230

1.385

-

32

-

0.0

Total

130

32

-

Gathering & Processing total

24,352

14,200

7,809

$
(37.3
)

Other (1)(2)

Future
C2-OPIS-MB

0.2741

13,804

-

-

$
(0.1
)
Future
C2-OPIS-MB

0.3007

-

1,534

-

0.2

Future
C2-OPIS-MB

0.3138

-

-

329

(0.0
)
Total

13,804

1,534

329

Future
C3-OPIS-MB

0.6394

13,120

-

-

(13.5
)
Future
C3-OPIS-MB

0.6074

-

2,918

-

(15.3
)
Total

13,120

2,918

-

Future
IC4-OPIS-MB

0.7706

1,033

-

-

(1.1
)
Future
IC4-OPIS-MB

0.7825

-

55

-

(0.2
)
Total

1,033

55

-

Future
NC4-OPIS-MB

0.8314

9,946

-

-

(8.2
)
Future
NC4-OPIS-MB

0.8027

-

1,616

-

(5.3
)
Total

9,946

1,616

-

Future
C5-OPIS-MB

1.1285

978

-

-

(0.3
)
Future
C5-OPIS-MB

1.0890

-

466

-

(0.8
)
Total

978

466

-

Put Price

Option
C2-OPIS-MB

0.2694

2,174

-

-

0.1

Option
C2-OPIS-MB

0.2963

-

1,644

-

1.1

Total

2,174

1,644

-

Other total

41,055

8,233

329

$
(43.4
)

$
(80.7
)

These contracts may expose us to the risk of financial loss in certain circumstances. Generally, our hedging arrangements provide us protection on the hedged volumes if prices decline below the prices at which these hedges are set. If prices rise above the prices at which they have been hedged, we will receive less revenue on the hedged volumes than we would receive in the absence of hedges (other than with respect to purchased calls). ~~For~~

To analyze the risk associated with our derivative instruments, we utilize a sensitivity analysis. The sensitivity analysis measures the change in fair value of our derivative instruments based on a hypothetical 10% change in the underlying commodity prices, but does not ~~designated as cash flow hedges, these contracts are marked-to-market and recorded in revenues.~~

~~We account for~~reflect the impact that the same hypothetical price movement would have on the related hedged items. The financial statement impact on the fair value of a derivative instrument resulting from a change in commodity price would normally be offset by a corresponding gain or loss on the hedged item under hedge accounting. The fair values of our ~~financial assets~~derivative instruments are also influenced by changes in market volatility for option contracts and ~~liabilities using a three-tier fair value hierarchy, which prioritizes~~ the ~~significant inputs~~discount rates used in measuring fair value. These tiers include: Level 1, defined as observable inputs such as quoted prices in active markets; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs in which little or no market data exists, therefore requiring an entity to ~~develop its own assumptions. We~~ determine the present values.

The following table shows the effect of hypothetical price movements on the estimated fair value of our derivative ~~contracts utilizing a discounted cash flow model~~instruments as of September 30, 2020:

The table above contains all derivative instruments outstanding as of the stated date for ~~swaps and a standard option pricing model for options, based on inputs that are readily available in public markets. For~~ the ~~contracts that have inputs from quoted prices, the classification~~purpose of ~~these instruments is Level 2 within the fair value hierarchy. For those contracts~~hedging commodity price risk, which we are ~~unable~~exposed to ~~obtain quoted~~due to our equity volumes and future commodity purchases and sales, as well as basis differentials related to our gas transportation arrangements.

Our operating revenues increased (decreased) by $109.2 million and $(61.8) million during the three months ended September 30, 2020 and 2019 and $337.3 million and $(7.7) million during the nine months ended September 30, 2020 and 2019, as a result of transactions accounted for as derivatives. We account for derivatives designated as hedges that mitigate commodity price risk as cash flow hedges. Changes in fair value are deferred in other comprehensive income until the underlying hedged transactions settle. We also enter into derivative instruments to help manage other short-term commodity-related business risks. We have not designated these derivatives as hedges and record changes in fair value and cash settlements to revenues.

The estimated fair value of our risk management position has moved from a net liability position of $6.1 million at December 31, 2019 to a net liability position of $15.6 million at September 30, 2020. The fixed prices we currently expect to receive on derivative contracts are below the aggregate forward prices for ~~at least 90% of the full term of the commodity contract, the valuations are classified as Level 3~~

~~within the fair value hierarchy. See Note 14 - Fair Value Measurements in~~commodities related to those contracts, creating this ~~Quarterly Report for more information regarding classifications within the fair value hierarchy.~~net liability position.

We are exposed to the risk of changes in interest rates, primarily as a result of variable rate borrowings under the TRP Revolver and the Securitization Facility. Additionally, on and after November 1, 2020, distributions on the Preferred Units will accumulate at an annual floating rate equal to the one-month LIBOR plus 7.71%. As of September 30, ~~2017,~~2020, we do not have any interest rate hedges. However, we may enter into interest rate hedges in the future with the intent to mitigate the impact of changes in interest rates on cash flows. To the extent that interest rates increase, interest expense for the TRP Revolver and the Securitization Facility, and distributions

owed on the Preferred Units, will also increase. As of September 30, ~~2017,~~2020, we had ~~$708.1~~$350.0 million in outstanding variable rate borrowings under the TRP Revolver and the Securitization Facility. A hypothetical change of 100 basis points in the ~~interest rate~~rates of our variable interest rate debt and Preferred Units accumulating at an annual floating rate would impact our annual interest expense by ~~$7.1 million.~~$3.5 million and Preferred Unit distributions by $1.3 million based on our September 30, 2020 debt balances.

We are subject to risk of losses resulting from nonpayment or nonperformance by our counterparties. The credit exposure related to commodity derivative instruments is represented by the fair value of the asset position (i.e. the fair value of expected future receipts) at the reporting date. Our futures contracts have limited credit risk since they are cleared through an exchange and are margined daily. Should the creditworthiness of one or more of the counterparties decline, our ability to mitigate nonperformance risk is limited to a counterparty agreeing to either a voluntary termination and subsequent cash settlement or a novation of the derivative contract to a third party. In the event of a counterparty default, we may sustain a loss and our cash receipts could be negatively impacted. We have master netting provisions in the International Swap Dealers Association agreements with ~~all~~ our derivative counterparties. These netting provisions allow us to net settle asset and liability positions with the same counterparties within the same Targa entity, and would reduce our maximum loss due to counterparty credit risk by ~~$32.4~~$67.0 million as of September 30, ~~2017.~~2020. The range of losses attributable to our individual counterparties as of September 30, 2020 would be between ~~$0.3~~$1.7 million and ~~$8.2~~$16.9 million, depending on the counterparty in default.

We extend credit to customers and other parties in the normal course of business. We have an established ~~policy and~~ various procedures to manage our credit exposure, ~~risk,~~ including performing initial and subsequent credit risk analyses, setting maximum credit limits and terms and requiring credit enhancements when necessary. We use credit enhancements including (but not limited to) letters of credit, prepayments, parental guarantees and rights of offset to limit credit risk to ensure that our established credit criteria are followed and financial loss is mitigated or minimized.

We have an active credit management process, which is focused on controlling loss exposure due to bankruptcies or other liquidity issues of counterparties. ~~If an assessment of uncollectible~~Our allowance for doubtful accounts ~~resulted in a 1% reduction of our third-party accounts receivable~~was $0.1 million and $0.0 million as of September 30, ~~2017, our operating income would decrease by $7.1 million~~2020 and December 31, 2019. Changes in the ~~year of~~allowance for doubtful accounts were not material for the ~~assessment.~~three and nine months ended September 30, 2020.

No customer comprised 10% or greater than our consolidated revenues during the three months ended September 30, 2020. During the nine months ended September 30, 2019, sales of commodities and fees from midstream services provided to Petredec (Europe) Limited comprised approximately 10% of our consolidated revenues.

During the three and nine months ended September 30, 2019, sales of commodities and fees from midstream services provided to Petredec (Europe) Limited comprised approximately 11% and 12% of our consolidated revenues.

Management, with the participation of our Chief Executive Officer and Chief Financial Officer, has evaluated the design and effectiveness of our disclosure controls and procedures, as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) as of the end of the period covered in this Quarterly Report. Based on such evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that, as of September 30, 2020, the design and operation of our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is (i) recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC and (ii) accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow for timely decisions regarding required disclosure.

There have been no changes in our internal control over financial reporting that occurred during the quarter that materially affected, or are reasonably likely to materially affect, our internal control over financial ~~reporting.~~reporting, during our most recent fiscal quarter.

On December 26, 2018, Vitol Americas Corp. (“Vitol”) filed a lawsuit in the 80^th District Court of Harris County, Texas against Targa Channelview LLC, a subsidiary of the Company (“Targa Channelview”), seeking recovery of $129.0 million in payments made to Targa Channelview, additional monetary damages, attorneys’ fees and costs. Vitol alleges that Targa Channelview breached an agreement, dated December 27, 2015, for crude oil and condensate between Targa Channelview and Noble Americas Corp. (the “Splitter Agreement”), which provided for Targa Channelview to construct a crude oil and condensate splitter (the “Splitter”) adjacent to a barge dock owned by Targa Channelview to provide services contemplated by the Splitter Agreement. In January 2018, Vitol acquired Noble Americas Corp. and on December 23, 2018, Vitol voluntarily elected to terminate the Splitter Agreement claiming that Targa Channelview failed to timely achieve start-up of the Splitter. Vitol’s lawsuit also alleges Targa Channelview made a series of misrepresentations about the capability of the barge dock that would service crude oil and condensate volumes to be processed by the Splitter and Splitter products. Vitol seeks return of $129.0 million in payments made to Targa Channelview prior to the start-up of the Splitter, as well as additional damages. On the same date that Vitol filed its lawsuit, Targa Channelview filed a lawsuit against Vitol seeking a judicial determination that Vitol’s sole and exclusive remedy was Vitol’s voluntarily termination of the Splitter Agreement and, as a result, Vitol was not entitled to the return of any prior payments under the Splitter Agreement or other damages as alleged. Targa also seeks recovery of its attorneys’ fees and costs in the lawsuit.

On October 15, 2020, the District Court awarded Vitol $129 million (plus interest) following a bench trial. In addition, the District Court awarded Vitol $10.5 million in damages for losses and demurrage on crude oil that Vitol purchased for start-up efforts. The Company plans to contest the award and is preparing an appeal to the Court of Appeals in Houston, Texas.

Additional information required for this item is provided in Note 1611 – Contingencies, under the heading “Legal Proceedings” included in the Notes to Consolidated Financial Statements included under Part I, Item 1 of this Quarterly Report, which is incorporated by reference into this item.

For an in-depth discussion of our risk factors, see “Part I—Item 1A. Risk Factors” of our Annual ~~Report.~~Report in addition to the risk factors discussed below. All of these risks and uncertainties, including those risks discussed below, could adversely affect our business, financial condition and/or results of operations.

Our cash flow is affected by supply and demand for natural gas, NGL products and crude oil and by natural gas, NGL, crude oil and condensate prices, and decreases in these prices could adversely affect our results of operations and financial condition.

Our operations can be affected by the level of natural gas, NGL and crude oil prices and the relationship between these prices. The prices of crude oil, natural gas and NGLs have been volatile, and we expect this volatility to continue. Our future cash flows may be materially adversely affected if we experience significant, prolonged price deterioration. The markets and prices for crude oil, natural gas and NGLs depend upon factors beyond our control. These factors include supply and demand for these commodities, which fluctuates with changes in market and economic conditions, and other factors, including:

Additionally, we have been and may continue to be adversely affected by the continued impact on global demand for commodities related to the COVID-19 pandemic. The COVID-19 pandemic has reduced economic activity and the related demand for energy commodities. These effects, combined with a period of increased production from major oil producing nations and decreasing availability of crude oil storage has contributed to lower commodity prices compared to historical levels in 2020 to date and is expected to continue to impact demand over the short-to-medium term.

Our primary natural gas gathering and processing arrangements that expose us to commodity price risk are our percent-of-proceeds arrangements. Under these arrangements, we generally process natural gas from producers and remit to the producers an agreed percentage of the proceeds from the sale of residue gas and NGL products at market prices or a percentage of residue gas and NGL products at the tailgate of our processing facilities. In some percent-of-proceeds arrangements, we remit to the producer a percentage of an index-based price for residue gas and NGL products, less agreed adjustments, rather than remitting a portion of the actual sales proceeds. Under these types of arrangements, our revenues and cash flows increase or decrease, whichever is applicable, as the prices of natural gas, NGLs and crude oil fluctuate, to the extent our exposure to these prices is unhedged. See “Item 3. Quantitative and Qualitative Disclosures About Market Risk.”

As further discussed in Note 4 – Property, Plant and Equipment and Intangible Assets and Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations, the global decline in commodity prices due to both demand and supply disruptions was a significant contributing factor to the non-cash impairment charges totaling $2,442.8 million for the nine months ended September 30, 2020.

The widespread outbreak of the COVID-19 pandemic or any other public health crisis that impacts the global demand for commodities may have material adverse effects on our business, financial position, results of operations and/or cash flows.

We face risks related to the outbreak of illnesses, pandemics and other public health crises that are outside of our control and could significantly disrupt our operations and adversely affect our financial condition. For example, the recent global spread of COVID-19 has caused business disruption, including disruption to the oil and gas industry. The COVID-19 pandemic has negatively impacted the global economy, disrupted global supply chains, reduced global demand for oil and gas, and created significant volatility and disruption of financial and commodity markets. The full extent of the impact of the COVID-19 pandemic on our operational and financial performance, including our ability to execute our business strategies and initiatives in the expected time frame, is uncertain and depends on various factors, including the demand for crude oil, natural gas and natural gas liquids (including the impact that reductions in travel, manufacturing and consumer product demand have had and will have on the demand for commodities), the availability of personnel, equipment and services critical to our ability to operate our assets and the impact of potential governmental restrictions on travel, transportation and operations.

The degree to which the COVID-19 pandemic or any other public health crisis adversely impacts our results will also depend on future developments, which are highly uncertain and cannot be predicted. These developments include, but are not limited to, the duration and spread of the outbreak, its severity, the actions to contain the virus or treat its impact, its impact on the economy and market conditions, and how quickly and to what extent normal economic and operating conditions can resume. Therefore, while we expect this matter will continue to disrupt our operations in some way, the degree of the adverse financial impact cannot be reasonably estimated at this time.

Refer to Note 4 – Property, Plant and Equipment and Intangible Assets and in Management's Discussion and Analysis of Financial Condition and Results of Operations, for further discussion.

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

~~Delaware~~		~~65-1295427~~
~~(State or other jurisdiction of incorporation or organization)~~		~~(I.R.S. Employer Identification No.)~~

~~1000 Louisiana St, Suite 4300, Houston, Texas~~		~~77002~~
~~(Address of principal executive offices)~~		~~(Zip Code)~~

~~Large accelerated filer~~	☐		~~Accelerated filer~~	☐
~~Non-accelerated filer~~	☑	~~(Do not check if a smaller reporting company)~~	~~Smaller reporting company~~	☐
			~~Emerging growth company~~	☐

~~TABLE OF CONTENTS~~ ~~PART I—FINANCIAL INFORMATION~~

~~Item 1. Financial Statements~~		4

~~Consolidated Balance Sheets as of September 30, 2017 and December 31, 2016~~		4

~~Consolidated Statements of Operations for the three and nine months ended September 30, 2017 and 2016~~		5

~~Consolidated Statements of Comprehensive Income (Loss) for the three and nine months ended September 30, 2017 and 2016~~		6

~~Consolidated Statements of Changes in Owners' Equity for the nine months ended September 30, 2017 and 2016~~		7

~~Consolidated Statements of Cash Flows for the nine months ended September 30, 2017 and 2016~~		8

~~Notes to Consolidated Financial Statements~~		9

~~Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations~~		36

~~Item 3. Quantitative and Qualitative Disclosures About Market Risk~~		57

~~Item 4. Controls and Procedures~~		62

~~PART II—OTHER INFORMATION~~

~~Item 1. Legal Proceedings~~		63

~~Item 1A. Risk Factors~~		63

~~Item 2. Unregistered Sales of Equity Securities and Use of Proceeds~~		63

~~Item 3. Defaults Upon Senior Securities~~		63

~~Item 4. Mine Safety Disclosures~~		63

~~Item 5. Other Information~~		63

~~Item 6. Exhibits~~		64

~~SIGNATURES~~

~~Signatures~~		66


~~Bbl~~	~~Barrels (equal to 42 U.S. gallons)~~
~~BBtu~~	~~Billion British thermal units~~
~~Bcf~~	~~Billion cubic feet~~
~~Btu~~	~~British thermal units, a measure of heating value~~
/d	~~Per day~~
~~GAAP~~	~~Accounting principles generally accepted in the United States of America~~
~~gal~~	~~U.S. gallons~~
~~GPM~~	~~Liquid volume equivalent expressed as gallons per 1000 cu. ft. of natural gas~~
~~LACT~~	~~Lease Automatic Custody Transfer~~
~~LIBOR~~	~~London Interbank Offered Rate~~
~~LPG~~	~~Liquefied petroleum gas~~
~~MBbl~~	~~Thousand barrels~~
~~MMBbl~~	~~Million barrels~~
~~MMBtu~~	~~Million British thermal units~~
~~MMcf~~	~~Million cubic feet~~
~~MMgal~~	~~Million U.S. gallons~~
~~NGL(s)~~	~~Natural gas liquid(s)~~
~~NYMEX~~	~~New York Mercantile Exchange~~
~~NYSE~~	~~New York Stock Exchange~~


~~Price Index Definitions~~
~~C2-OPIS-MB~~	~~Ethane, Oil Price Information Service, Mont Belvieu, Texas~~
~~C3-OPIS-MB~~	~~Propane, Oil Price Information Service, Mont Belvieu, Texas~~
~~C5-OPIS-MB~~	~~Natural Gasoline, Oil Price Information Service, Mont Belvieu, Texas~~
~~EP-PERMIAN~~	~~Inside FERC Gas Market Report, El Paso (Permian Basin)~~
~~IC4-OPIS-MB~~	~~Iso-Butane, Oil Price Information Service, Mont Belvieu, Texas~~
~~IF-PB~~	~~Inside FERC Gas Market Report, Permian Basin~~
~~IF-PEPL~~	~~Inside FERC Gas Market Report, Oklahoma Panhandle, Texas-Oklahoma Midpoint~~
~~IF-Waha~~	~~Inside FERC Gas Market Report, West Texas WAHA~~
~~NC4-OPIS-MB~~	~~Normal Butane, Oil Price Information Service, Mont Belvieu, Texas~~
~~NG-NYMEX~~	~~NYMEX, Natural Gas~~
~~WTI-NYMEX~~	~~NYMEX, West Texas Intermediate Crude Oil~~

Bbl	Barrels (equal to 42 U.S. gallons)
BBtu	Billion British thermal units
Bcf	Billion cubic feet
Btu	British thermal units, a measure of heating value
/d	Per day
GAAP	Accounting principles generally accepted in the United States of America
gal	U.S. gallons
LIBOR	London Interbank Offered Rate
LPG	Liquefied petroleum gas
MBbl	Thousand barrels
MMBbl	Million barrels
MMBtu	Million British thermal units
MMcf	Million cubic feet
MMgal	Million U.S. gallons
NGL(s)	Natural gas liquid(s)
NYMEX	New York Mercantile Exchange
NYSE	New York Stock Exchange
SCOOP	South Central Oklahoma Oil Province
STACK	Sooner Trend, Anadarko, Canadian and Kingfisher


Title of each class	Trading Symbol(s)	Name of exchange on which registered
9.0% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units	NGLS/PA	New York Stock Exchange

Large accelerated filer	☐	Accelerated filer	☐
Non-accelerated filer	☑	Smaller reporting company	☐
		Emerging growth company	☐

TABLE OF CONTENTS PART I—FINANCIAL INFORMATION

Item 1. Financial Statements		4

Consolidated Balance Sheets as of September 30, 2020 and December 31, 2019		4

Consolidated Statements of Operations for the three and nine months ended September 30, 2020 and 2019		5

Consolidated Statements of Comprehensive Income (Loss) for the three and nine months ended September 30, 2020 and 2019		6

Consolidated Statements of Changes in Owners' Equity for the three and nine months ended September 30, 2020 and 2019		7

Consolidated Statements of Cash Flows for the nine months ended September 30, 2020 and 2019		9

Notes to Consolidated Financial Statements		10

Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations		26

Item 3. Quantitative and Qualitative Disclosures About Market Risk		44

Item 4. Controls and Procedures		46

PART II—OTHER INFORMATION

Item 1. Legal Proceedings		47

Item 1A. Risk Factors		47

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		48

Item 3. Defaults Upon Senior Securities		48

Item 4. Mine Safety Disclosures		49

Item 5. Other Information		49

Item 6. Exhibits		50

SIGNATURES

Signatures		52

	September 30, 2020			December 31, 2019			Estimated Useful Lives (In Years)
Gathering systems	$	9,125.1		$	8,976.8		5 to 20
Processing and fractionation facilities		6,131.7			5,137.0		5 to 25
Terminaling and storage facilities		1,514.8			1,495.5		5 to 25
Transportation assets		2,422.6			2,292.4		10 to 50
Other property, plant and equipment		123.7			183.9		3 to 50
Land		160.7			159.7		—
Construction in progress		697.8			1,576.5		—
Finance lease right-of-use assets		51.3			48.8
Property, plant and equipment		20,227.7			19,870.6
Accumulated depreciation, amortization and impairment		(7,934.8	)		(5,321.6	)
Property, plant and equipment, net	$	12,292.9		$	14,549.0

Intangible assets	$	2,643.5		$	2,643.5		10 to 20
Accumulated amortization and impairment		(1,225.9	)		(908.5	)
Intangible assets, net	$	1,417.6		$	1,735.0

Fair Value of Consideration Transferred:
Cash paid, net of $3.3 million cash acquired	$	570.8
Contingent consideration valuation as of the acquisition date		416.3
Total	$	987.1

Fair value determination (final):	March 1, 2017
Trade and other current receivables, net	$	6.7
Other current assets		0.6
Property, plant and equipment		255.8
Intangible assets		692.3
Current liabilities		(14.1	)
Other long-term liabilities		(0.8	)
Total identifiable net assets		940.5
Goodwill		46.6
Total fair value of assets acquired and liabilities assumed	$	987.1

	September 30, 2017		December 31, 2016
Commodities	$	255.6	$	126.9
Materials and supplies		11.8		10.8
	$	267.4	$	137.7

Balance at December 31, 2016	$	1,654.0
Additions from Permian Acquisition		692.3
Additions from Flag City Acquisition		7.7
Amortization		(139.2	)
Balance at September 30, 2017	$	2,214.8

Balance at December 31, 2019	$	1,735.0
Impairment		(208.6	)
Amortization		(108.8	)
Balance at September 30, 2020	$	1,417.6

	WestTX		SouthTX		Permian		Total
Balance at December 31, 2016, net	$	174.7	$	35.3	$	—	$	210.0
Permian Acquisition, March 1, 2017		—		—		46.6		46.6
Balance at September 30, 2017, net	$	174.7	$	35.3	$	46.6	$	256.6

	September 30, 2020
Current assets:
Property, plant and equipment, net of accumulated depreciation and estimated loss on sale	$	61.0
Other current assets		1.2
Total assets held for sale	$	62.2

Current liabilities:
Accounts payable and accrued liabilities	$	1.0
Other long-term obligations		2.6
Total liabilities held for sale	$	3.6

	GCF			T2 LaSalle			T2 Eagle Ford			T2 EF Cogen			Cayenne		Total
Balance at December 31, 2016	$	46.1		$	58.6		$	118.6		$	17.5		$	—	$	240.8
Equity earnings (loss)		8.4			(3.7	)		(7.9	)		(13.4	)		—		(16.6	)
Cash distributions (1)		(10.6	)		—			—			—			—		(10.6	)
Acquisition		—			—			—			—			5.0		5.0
Contributions (2)		—			0.4			1.2			0.1			1.8		3.5
Balance at September 30, 2017	$	43.9		$	55.3		$	111.9		$	4.2		$	6.8	$	222.1

Debt Repurchased	Book Value		Payment			Gain (Loss)			Write-off of Debt Issuance Costs			Net Gain
5⅛% Senior Notes due 2025	$	19.0	$	(14.6	)	$	4.4		$	(0.1	)	$	4.3
5⅞% Senior Notes due 2026		36.8		(29.7	)		7.1			(0.2	)		6.9
5⅜% Senior Notes due 2027		31.9		(26.6	)		5.3			(0.2	)		5.1
6½% Senior Notes due 2027		44.8		(35.5	)		9.3			(0.4	)		8.9
5% Senior Notes due 2028		49.7		(38.0	)		11.7			(0.4	)		11.3
6⅞% Senior Notes due 2029		70.7		(55.2	)		15.5			(0.6	)		14.9
5½% Senior Notes due 2030		50.4		(40.2	)		10.2			(0.5	)		9.7
6¾% Senior Notes due 2024		580.1		(591.2	)		(11.1	)		(2.6	)		(13.7	)
	$	883.4	$	(831.0	)	$	52.4		$	(5.0	)	$	47.4

	Payments Due By Period
			Less Than						More Than
	Total		1 Year		1-3 Years		3-5 Years		5 Years
	(in millions)
Long-term debt obligations (1)	$	7,244.8	$	-	$	714.2	$	1,064.9	$	5,465.7
Interest on debt obligations (2)		2,729.3		402.0		791.0		657.6		878.7
	$	9,974.1	$	402.0	$	1,505.2	$	1,722.5	$	6,344.4

	September 30, 2017		December 31, 2016
Asset retirement obligations	$	49.4	$	64.1
Mandatorily redeemable preferred interests		80.0		68.5
Deferred revenue		67.5		69.8
Permian Acquisition contingent consideration, noncurrent portion		284.9		—
Other liabilities		3.1		2.9
Total long-term liabilities	$	484.9	$	205.3

Balance at December 31, 2016	$	64.1
Additions (1)		0.8
Reduction due to sale of VGS		(21.6	)
Change in cash flow estimate		3.1
Accretion expense		3.0
Balance at September 30, 2017	$	49.4

Balance at December 31, 2016	$	68.5
Income attributable to mandatorily redeemable preferred interests		3.0
Change in estimated redemption value included in interest expense		8.5
Balance at September 30, 2017	$	80.0

	September 30, 2017		December 31, 2016
Splitter agreement	$	43.0	$	43.0
Gas contract amendment		18.6		19.7
Other deferred revenue		5.9		7.1
Total deferred revenue	$	67.5	$	69.8

Balance at December 31, 2016	$	69.8
Additions		—
Revenue recognized		(2.3	)
Balance at September 30, 2017	$	67.5

Balance at March 1, 2017 (acquisition date)	$	461.6
Measurement period adjustment of acquisition date value		(45.3	)
Decrease in fair value due to factors occurring after acquisition date		(125.5	)
Balance at September 30, 2017		290.8
Less: Current portion		(5.9	)
Long-term balance at September 30, 2017	$	284.9

Three Months Ended	Date Paid Or to Be Paid		Total Distributions			Distributions to Targa Resources Corp.
September 30, 2017	November 10, 2017	$		225.4	$		222.6
June 30, 2017	August 10, 2017			225.4			222.6
March 31, 2017	May 11, 2017			209.6			206.8
December 31, 2016	February 10, 2017			198.1			195.3

Three Months Ended	Date Paid or To Be Paid		Total Distributions			Distributions to Targa Resources Corp.
September 30, 2020	November 13, 2020	$		51.7	$		48.9
June 30, 2020	August 13, 2020			51.7			48.9
March 31, 2020	May 13, 2020			53.1			50.3
December 31, 2019	February 13, 2020			241.9			239.1

		Commodity
		Derivative Contracts			Contingent
		Asset/(Liability)			Liability

Balance, December 31, 2016		$	(3.6	)	$	(2.6	)
	Change in fair value of TPL contingent consideration		-			0.1
	Fair value of Permian Acquisition contingent consideration (1)		-			(290.8	)
	New Level 3 derivative instruments		(0.8	)		-
	Transfers out of Level 3 (2)		1.6			-
	Settlements included in Revenue		0.4			-
	Unrealized gain/(loss) included in OCI		(3.5	)		-
Balance, September 30, 2017		$	(5.9	)	$	(293.3	)

	2020				2021				2022 and after
Fixed consideration to be recognized as of September 30, 2020	$	140.7			$	518.1			$	2,858.8

	Nine Months Ended September 30, 2017
	Gathering and Processing		Logistics and Marketing		Other		Corporate and Eliminations			Total
Revenues
Sales of commodities	$	544.4	$	4,804.8	$	3.9	$	—		$	5,353.1
Fees from midstream services		399.3		359.7		—		—			759.0
		943.7		5,164.5		3.9		—			6,112.1
Intersegment revenues
Sales of commodities		2,209.2		237.8		—		(2,447.0	)		—
Fees from midstream services		5.1		21.1		—		(26.2	)		—
		2,214.3		258.9		—		(2,473.2	)		—
Revenues	$	3,158.0	$	5,423.4	$	3.9	$	(2,473.2	)	$	6,112.1
Operating margin	$	549.3	$	358.5	$	3.9	$	—		*
Other financial information:
Total assets (1)	$	10,644.3	$	3,240.9	$	30.8	$	56.2		$	13,972.2
Goodwill	$	256.6	$	—	$	—	$	—		$	256.6
Capital expenditures	$	730.7	$	241.8	$	—	$	15.2		$	987.7
Business acquisition	$	987.1	$	—	$	—	$	—		$	987.1

		Gathering and Processing		Logistics and Marketing		Other			Total
	(In millions)
Three Months Ended:
September 30, 2017		$	198.3	$	115.9	$	(1.0	)	$	313.2
September 30, 2016			149.4		126.0		11.2			286.6

Nine Months Ended:
September 30, 2017		$	549.3	$	358.5	$	3.9		$	911.7
September 30, 2016			404.1		424.6		56.9			885.6

	Three Months Ended September 30, 2017
Operating statistics:
Plant natural gas inlet, MMcf/d (1),(2)	Gross Volume (3)		Ownership %			Net Volume (3)		Actual Reported
SAOU (4)		324.6		100	%		324.6		324.6
WestTX (5) (6)		834.5		73	%		607.5		607.5
Total Permian Midland		1,159.1					932.1		932.1
Sand Hills (4)		193.0		100	%		193.0		193.0
Versado (7)		210.9		100	%		210.9		210.9
Total Permian Delaware		403.9					403.9		403.9
Total Permian		1,563.0					1,336.0		1,336.0

SouthTX		330.1	Varies (8) (9)				260.0		330.1
North Texas		261.8		100	%		261.8		261.8
SouthOK		515.2	Varies (10)				412.1		515.2
WestOK		367.1		100	%		367.1		367.1
Total Central		1,474.2					1,301.0		1,474.2

Badlands (11)		60.9		100	%		60.9		60.9
Total Field		3,098.1					2,697.9		2,871.1

Gross NGL production, MBbl/d (2)
SAOU (4)		38.7		100	%		38.7		38.7
WestTX (5) (6)		115.5		73	%		84.1		84.1
Total Permian Midland		154.2					122.8		122.8
Sand Hills (4)		21.0		100	%		21.0		21.0
Versado (7)		25.3		100	%		25.3		25.3
Total Permian Delaware		46.3					46.3		46.3
Total Permian		200.5					169.1		169.1

SouthTX		35.4	Varies (8) (9)				28.6		35.4
North Texas		29.3		100	%		29.3		29.3
SouthOK		42.7	Varies (10)				34.6		42.7
WestOK		20.7		100	%		20.7		20.7
Total Central		128.1					113.2		128.1

Badlands		9.0		100	%		9.0		9.0
Total Field		337.6					291.3		306.2

Instrument		Price
Type	Index	$/MMBtu					MMBtu/d											Fair Value
							2017			2018			2019			2020		(In millions)
Gathering & Processing
Swap	IF-Waha		2.8740					103,600			-			-			-	$	2.7
Swap	IF-Waha		2.6470					-			93,600			-			-		4.0
Swap	IF-Waha		2.6327					-			-			65,383			-		6.2
								103,600			93,600			65,383			-

Swap	IF-PB		2.6602					40,900			-			-			-		0.5
Swap	IF-PB		2.4802					-			45,900			-			-		0.2
Swap	IF-PB		2.3700					-			-			35,000			-		0.9
								40,900			45,900			35,000			-

Swap	IF-PEPL		2.6835					16,000			-			-			-		0.1
Swap	IF-PEPL		2.6835					-			16,000			-			-		0.6
Swap	IF-PEPL		2.6835					-			-			16,000			-		1.5
								16,000			16,000			16,000			-

Swap	NG-NYMEX		3.9900					9,783			-			-			-		0.8


		Put Price			Call Price
Collar	IF-Waha		3.0000			3.6700		7,500			-			-			-		0.3
Collar	IF-Waha		3.2500			4.2000		-			1,849			-			-		0.3
								7,500			1,849			-			-

		Put Price			Call Price
Collar	IF-PB		2.8000			3.5000		15,400			-			-			-		0.4
Collar	IF-PB		3.0000			3.6500		-			7,637			-			-		1.5
								15,400			7,637			-			-


Basis Swap	EP-PERMIAN		(0.1444	)				4,891			-			-			-		0.2

Basis Swap	PEPL		(0.3308	)				4,891			-			-			-		0.0

Gathering & Processing total								202,965			164,986			116,383			0	$	20.2

Other (1)
Swap	NG-NYMEX		(3.1680	)				(229	)		(173	)		(247	)		-	$	(0.0	)
Swap	IF-Waha		3.0647					(9,707	)		(4,227	)		-			-		(0.5	)
Basis Swap	Various	Various						82,418			15,726			12,500			10,445		(1.3	)
Future	Various		3.2640					-			1,103			-			-		(0.0	)
Other total								72,482			12,429			12,253			10,445	$	(1.8	)

																		$	18.4


Future	IC4-OPIS-MB	0.7706	1,033	-	-		(1.1	)
Future	IC4-OPIS-MB	0.7825	-	55	-		(0.2	)
Total			1,033	55	-

Future	NC4-OPIS-MB	0.8314	9,946	-	-		(8.2	)
Future	NC4-OPIS-MB	0.8027	-	1,616	-		(5.3	)
Total			9,946	1,616	-

Future	C5-OPIS-MB	1.1285	978	-	-		(0.3	)
Future	C5-OPIS-MB	1.0890	-	466	-		(0.8	)
Total			978	466	-

	Put Price
Option	C2-OPIS-MB	0.2694	2,174	-	-		0.1
Option	C2-OPIS-MB	0.2963	-	1,644	-		1.1
Total			2,174	1,644	-

Other total			41,055	8,233	329	$	(43.4	)

						$	(80.7	)

	Fair Value			Result of 10% Price Decrease		Result of 10% Price Increase
Natural gas	$	7.8		$	49.7	$	(33.6	)
NGLs		(55.1	)		11.0		(121.2	)
Crude oil		31.7			45.4		18.0
Total	$	(15.6	)	$	106.1	$	(136.8	)